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SEPLAT Starts Commissioning an Alternative Pipeline, Ten Years after Construction Began

Seplat Energy has struggled for uptime in pumping its crude through the Trans Forcados Pipeline, a frequently vandalized facility in Nigeria’s Western Niger Delta.

Now the company has commenced commissioning of the Amukpe-Escravos Pipeline (AEP) and looks forward to oil flow “in December 2021”, it says in its latest update.

The AEP will provide an alternative evacuation route to Trans Forcados Pipeline, which was down for two weeks in September 2021, pushing Seplat’s gross (operated) output to less than 60,000BOPD.

Seplat had anticipated, in its second quarter 2021 (2Q 2021) update “to introduce hydrocarbons into the line by the end of September, 2021 and during 4Q to lift our crude via the Escravos terminal upon completion of the crude handling agreements (CHA) with Chevron”.

But the September 2021 deadline passed. “Procedure is being reviewed and we’re working to close out a few open switches prior to introducing Hydrocarbon”, explain management sources at the Nigerian Petroleum Development Company (NPDC), the state hydrocarbon firm in joint venture with Seplat in the Western Niger Delta.

Construction of the 160,000Barrels of Oil Per Day (BOPD) evacuation facility was begun by the Nigerian independent, Pan Ocean Overseas, in October 2011. It is a 20”X67km Crude Oil pipeline which is meant to serve as an alternative (ultimately the mainstay) to the existing Seplat/Shell 24”/28” export pipeline to the export terminal at Forcados on the Atlantic Ocean.

“The completion of minor tie-in works on the Pipeline, which are not within Seplat Energy’s direct control, have been slower than anticipated due to a combination of challenges associated with access to the Escravos terminal owing to Covid-19 protocols and providing clarifications with the owners of the pipeline”, Seplat explained in the briefing last July.

“Our partner, NPDC owns a direct stake in the pipeline and are now actively working with Seplat Energy and the pipeline owners and their respective banks, to enable the final completion of the project. The construction of the entire pipeline system – including the metering facilities, is effectively complete and the precommissioning process is progressing well. This process involves functional testing of key components and operating systems integration with the receiving terminal facilities.

“The imminent conclusion of this project will significantly improve our assets’ production uptime compared with the TransForcdos Pipeline TFP (81% in H1 2021) and reduce losses from crude theft and reconciliation (12.1% in H1 2021)”, the Seplat update explained.


ExxonMobil’s Next Move: Is there a Plan B?

Gerard Kreeft

Will ExxonMobil’s Board decide to exit from its Rovuma LNG project in Mozambique? Gas reserves are estimated at 80Trillion Cubic Feet (80Tcf) and the cost for developing the field are estimated at more than $30Billion. The mere fact that such a discussion is taking place leaves pundits scratching their heads.

Surely in the midst of the energy transition such a project with its abundance of natural gas is the symbol of moving towards a cleaner fuel.

ExxonMobil is in a state of turbulence. Once seen as the oil and gas industry leader, the Dallas headquartered supermajor is in uncharted waters. Its biggest challenges are legal, not the search for oil and gas: ExxonMobil’s management has been forced to accept three new board members, nominated by Engine Number 1, a small, but very influential investor; and an environmental court challenge which potentially could derail its Deepwater Guyana projects.  Surely the court decision in the Netherlands ordering Shell to cut by 2030 its CO2 emissions by 45%, compared to 2019 levels, is a decision being followed closely by the courts in Guyana and the boardroom of ExxonMobil. Afterall, ExxonMobil’s upstream activities in the Netherlands and the UK are joint-ventured with Shell.

ExxonMobil has written down between $17–$20Billion in impairment charges, and is capping capital spending at $25Billion a year through 2025, a $10Billion reduction from pre-pandemic levels. Its market capitalization now hovers at $250Billion; in October 2020 ExxonMobil’s  market cap plunged to $140Billion.

Clark Williams-Derry and Tom Sanzillo, IEEFA(Institute for Energy Economics and Financial Analysis) recently reported that ExxonMobil has since 2013 invested $61.5Billion on US upstream capital projects, only to report $5.3Billion in cumulative losses(see below).

To meet the green challenge ExxonMobil has unveiled a plan to build one of the world’s largest carbon capture and storage (CCS) projects along the Houston Ship Channel in Texas. The proposed project would cost $100Billion and would capture and store 100Million metric tons of CO2 per year. The emissions saved would be equivalent to removing 1 in every 12 cars on US roads, the company says. ExxonMobil is proposing to build infrastructure to capture its own CO2 emissions, as well as those from power plants, oil refineries, and chemical plants in the Houston area.

For the project to be economically viable, it would need major public funding and the introduction of a price on carbon in the US. ExxonMobil says the project could be fully operational by 2040.

Yet public reactions are at best muted and at worst cynical. Carbon Market Watch sees CCS “as a lengthy distraction from the debate about greenhouse gas pollution from fossil fuels and getting emissions down at source”.

CCS can perhaps be seen as a partial measure to reduce a company’s CO2 footprint; however, only within the structured framework of a green energy roadmap. Not as a smoke screen in a continued broken hydrocarbon narrative.

What ExxonMobil fails to understand is that since the Paris Climate Agreement of December 2015 the industry landscape has changed drastically. Shareholders are demanding an energy transition strategy in which key renewables play a key role and CO2 emissions levels are drastically reduced.

ExxonMobil’s reaction has been– less spending on hydrocarbons with the hope for a better day. No renewable vision. A company in retreat. Certainly a project such as Rovuma with potential gas reserves of some 80Tcf should be the centre of any long-term energy transition  strategy, given the importance of natural gas in the transition phase. Yet because of its religious belief in only exploring for hydrocarbons it has painted itself in a corner.

A Contrasting Vision

A contrasting vision is that of TOTALEnergies. In the summer of 2020 French oil and gas giant TOTALEnergies  announced a $7Billion impairment charge for two Canadian oil sands projects. This might have seemed like an innocuous move, merely an acknowledgement that the projects hadn’t worked out as planned.

Yet it opened a Pandora’s box that could change the way the industry thinks about its core business model—and point the way towards a new path to financial success in the energy sector.

While it wrote off some weak assets, it 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 chief executive, now says that by 2030 the company “will grow by one-third, roughly from 3Million BOE/D (Barrels of Oil Equivalent per Day) to 4Million BOE/D, half from LNG, half from electricity, mainly from renewables.” This was the first time that any major energy company  translated its renewable energy portolio into barrels of oil equivalent. So, at the same time that the company has slashed “proved” oil and gas from its books, it added renewable power as a new form of reserves.

Each of the oil and gas majors spilled red ink in 2020, and most took significant write-downs. But TOTALEnergies’ tar sands impairments were different. The company wrote off “proved reserves,” or oil and gas that the company had previously deemed all-but-certain to be produced.

Proved 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 proved reserves with wealth and a harbinger of long-term profits.

Because reserves were so important, the Reserve Replacement Ratio, or 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 U.S. Securities and Exchange Commission. An annual RRR of 100% became the norm.

But TOTALEnergies’ write-off showed that even “proved” 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 “proved” 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. Given current forecasts that prices would remain lower for longer, TOTALEnergies’ financial team decided those resources could never be developed at a profit.

On the renewables front, TOTALEnergies has confirmed that it will have a 35 gigawatt (GW) capacity by 2025, and hopes to add 10GW per year after 2025. That could mean an additional 250GW by 2050.

A key to TOTALEnergies success is its willingness to devote capital to projects at an early stage. Its renewable investments include:

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

TOTALEnergies’ renewable investments will add ballast, keeping it afloat. The company hasn’t abandoned oil and gas, and its hydrocarbon investments may prove problematic over the long term. But its renewable investments will add ballast to the company’s balance sheets, keeping it afloat as it carefully chooses investments, including oil and gas projects, with a high economic return.

Taking on renewables has enabled TOTALEnergies to broaden its portfolio and take on additional risks. Perhaps a key reason why TOTALEnergies in 2022  will possibly continue with its Mozambique LNG project and ExxonMobil will be probably exiting the country.

-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 the Institute Energy Economics and Financial Analysis (IEEFA).

NETCO Snagged Six Contracts in 2020, Says NNPC Annual Report

NETCO, the engineering service subsidiary of Nigeria’s state hydrocarbon firm NNPC, won six contract awards worth over $57Million in 2020, the company says in its annual report.

Five of the contracts were awarded by NETCO’s fellow subsidiaries in NNPC group. Three of them were for projects relating to rehabilitation of the dilapidated refineries and one was for an engineering study evaluating a westward extension of the Escravos Lagos Pipeline system (ELPS).  Only one of the contracts was awarded by an entity outside.

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Chinese Coal Imports from Mozambique, South Africa, in a Historic Surge

Export of coal from Mozambique and South Africa to China has leaped to a historic high in 2021, as the world’s second largest economy buys from new sources to deal with a global coal shortage.

As the market has tightened, China started importing from these two countries, which are not its non-traditional markets, like South Africa and Mozambique and expanded its trade with existing trading partners, including Myanmar Colombia and Kazakhstan.

China’s trade in coal with Mozambique and South Africa has a history. The Asian giant returned to import from South Africa years after it stopped as a result of problems with the chemistry of South African coal. Imports from South Africa, mostly used for coal to power generation, moved from zero in December 2020, to 1 Million tonnes in April 2021.

China’s coal trade with Mozambique was active between 2011 and 2014, when it stopped. It was restarted in February 2021. Monthly imports from Mozambique reached 174,000 tonnes in April, the highest level on record, according figures quoted by South China Morning Post.



Angola’s Oil Industry –The Turn Around Begins

By Tako Koning

Angola’s oil industry has been low profile the past few years with no really significant major oil or gas discoveries.

Oil production from the country’s mature oil fields continues to decline steadily from a peak production of 2Million barrels of oil per day in 2008 to the current 1.13Million barrels per day.  But it is too early to write off Angola as an important oil producer in the global oil industry. One needs to be reminded that Angola remains Africa’s second-largest oil producer after Nigeria.

In the past few weeks, events have happened which point to a turnaround in Angola’s oil industry.

1.) Nine blocks in the onshore Lower Congo and Kwanza Basins were awarded to various small international and local Angolan oil companies. This is positive news. However, the existing subsurface geological and seismic data indicate that if exploration is successful, the new oil fields will likely be small. Future possible oil production from those areas likely will not materially impact Angola’s oil production. However, the activity there could build a reasonably sized onshore oil industry and create jobs which would be very important for Angola’s struggling economy. 

2.) TOTALEnergies announced they will commence this month the drilling of an exploration well on ultra-deepwater Block 48 in a world record-breaking water depth of 3,628 m (11,900 ft). This record was previously held by TOTALEnergies in an exploration well drilled in 2016 in 3,400 m (11,155 ft) water depth off Uruguay. A possible oil or gas discovery in Block 48, which is located in the Lower Congo Basin, will open up a wide range of similar prospects in this basin’s ultradeep waters. Accordingly, this well will be one of the world’s most high-profile wells to be drilled this year.

3.) This month, TOTALEnergies announced that following their recent successful appraisal well drilled in the Golfinho oil discovery, they will install a floating production project in the deepwater Kwanza Basin to produce oil from the Cameia and Golfinho oil fields. The FPSO will go online in 2026 and produce 100,000 barrels of oil per day. The importance of this announcement is under-appreciated by most oil industry observers and needs to be further explained.

The offshore Kwanza Basin has been explored for over a half-century, beginning in 1968 with the drilling in shallow water Block 7. Neither a drop of oil nor a cubic metre of gas has been produced in the basin since that time. However, beginning in 2011, Houston-based Cobalt International Energy made seven oil, gas, and condensate discoveries in Cretaceous-age pre-salt sediments. Due to a wide range of various issues, Cobalt went bankrupt in 2017 and its discoveries remained undeveloped. Thereafter, TOTALEnergies was awarded operatorship of the legacy Cobalt blocks. The French major re-evaluated the discoveries and remaining prospects and completed the successful Golfinho appraisal well. The Cameia – Golfinho production project will create an activity hub in this part of the Kwanza Basin which will result in a further reappraisal of the other Cobalt discoveries, prospects, and leads which could lead to additional oil production projects.  

At times, oil and gas explorers need to take a historical view of the exploration in any sedimentary basin. In the deepwater Kwanza Basin, in 2011 a huge drilling campaign commenced which was focused on exploring for oil in the pre-salt sediments. The objective was to try to duplicate in the Kwanza Basin the major oil discoveries made in Brazil’s pre-salt, including the giant Tupi (now Lula) and Libra oil discoveries. The operators included BP, TOTALEnergies, Repsol, ENI, Statoil, Maersk, Petrobras, and Cobalt. The results were very disappointing. Oil discoveries by Cobalt and Maersk were non-commercial. The campaign also resulted in natural gas discoveries which were relinquished by the oil companies since at that time they had no rights to the gas. For example, as unbelievable as it may now sound, ConocoPhillips drilled the Kamoxi-1 exploration well on Block 37 and walked away from a 160 m gas column in the pre-salt without testing it.

Since that time, Angola revamped its oil and gas legislation so that the companies are also entitled to any gas they discover. You can be sure that a number of companies have now taken a hard look at the possible appraisal of ConocoPhillips Kamoxi gas discovery in view of the high current and projected global gas prices. Accordingly, in my view, the deepwater Kwanza Basin could eventually host a floating Liquified Natural Gas (LNG) project if the threshold gas reserves for a commercial project are established.  

From a geologist’s point of view, the Kwanza Basin’s gas potential is promising. From an environmental viewpoint, such a project is positive since gas is the least carbon-emitting of the hydrocarbons. Most forecasts are that gas will be the critical “bridging fuel” in the rapidly increasing energy transition. From an economic viewpoint, such an LNG project could be commercially positive since gas prices continue to escalate and the need for gas keeps ramping up worldwide.  

In conclusion, there is lots of life left in the Angolan oil patch and the turn-around has just begun.

Tako Koning is a Calgary, Canada-based energy consultant who worked in Angola for twenty years from 1995 to 2015. He is a graduate of the University of Alberta with a B.Sc. in geology and from the University of Calgary with a B.A. in Economics. He is a registered professional geologist with the Association of Professional Engineers and Geoscientists of Alberta (APEGA). In Angola, Tako was employed mainly by Texaco but also later by Tullow Oil and the American/British consulting firm of Gaffney, Cline, & Associates.  He has been on the International Advisory Board of Africa Oil + Gas Report since its inception in 2001. In 1994, Tako was awarded Honorary Life Membership by the Nigerian Association of Petroleum Explorationists (NAPE) for his work with Nigeria’s university students and also for his assistance to NAPE.  

China is Close to Getting Concession of Angola’s Port of Lobito

The construction arm of China’s state-owned CITIC Group Corporation Ltd. (formerly the China International Trust Investment Corporation) is one of only two companies whose offers for the concession of the Port of Lobito, Angola, were admitted.

The other offer being considered came from International Container Terminal Services Inc (ICTSI), according to the Angolan Ministry of Transport.

The concession for the management and operation of the Multipurpose Container and Cargo Terminal at the Commercial Port of Lobito is for a period of 20 years, the ministry says.

Bolloré Logistics, the French-owned company with a wide Africa network, put in the preliminary bid, but it failed because it did not provide for the payment of the minimum amount of the concession fee of 80Million dollars under the terms of the tender specifications.

Dubai Port World, Yilport, Qterminal, and Abu Dhabi Ports all bid for the concession, but did not make an offer.

An evaluation committee will rate the proposals admitted to the competition, and the winner is expected to be announced before the end of 2021, according to the statement.

The container and general cargo terminal at the port of Lobito has a total area of ​​241,540.94 square metres, a berth of 1,199 linear metres, and the capacity to handle more than 600 thousand tons of non-containerized cargo and 250 thousand TEU (unit equivalent to 20 feet) per year, the Ministry of Transport claims.

CITIC Construction has branches in Algeria, Angola, Venezuela, Brazil, Argentina, Uzbekistan, Kazakhstan, Belarus, South Africa, Kenya, Russia, Myanmar, and a number of other overseas markets.

Eroton, Hurting, ‘Walks Out’ of the Nembe Creek Trunk Line, Halts Delivery of Crude through Bonny Terminal

By Toyin Akinosho

The Nigerian independent, Eroton, has stopped evacuating its crude to the Bonny Terminal through the Nembe Creek Trunk Line.

The operator of Oil Mining Lease (OML) 18, an onshore acreage in eastern Nigeria, commenced oil barging operations (shipping its cargoes on water) from the lease, to a Floating Storage Offshore vessel on the Atlantic, in late September 2021.

Although, Eroton had planned an alternative evacuation route for its crude for the last four years, this move came almost abruptly.

The company has struggled with massive crude oil theft by vandals along the 97kilometre NCTL, the newest and yet the most persistently damaged, crude to terminal evacuation pipeline in the country.

Eroton has the capacity to produce over 40,000 Barrels of Oil Per Day, but oil delivered to the Bonny Terminal for sales was approximately 6,600BOPD in first half 2021, compared with 25,200BOPD in first half 2020, according to recent update by San Leon, a London listed company which owns 10% of the acreage.

While OPEC restrictions have been a key part of the steep reduction, “third party terminal and gathering system issues”, (San Leon’s phrasing for Bonny Terminal and NCTL)  have been most responsible for the decline.

Kenya To Produce 120,000BOPD at Peak, if $3.4Billion Oilfield Project Goes Ahead

By Toyin Akinosho

Partners in Kenya’s two proven onshore acreages have high graded the field development plan for the basin-wide, crude oil project.

Far from the earlier proposed “foundation stage development” involving a 60,000 to 80,000Barrels of Oil Per Day (BOPD) Central Processing Facility (CPF) and an export pipeline to Lamu, the three companies: Tullow Oil (operator), Africa Oil Corp, and TOTALEnergies, have now informed the Government that Blocks 10BB and 13T licenses can deliver production plateau of 120,000BOPD, with expected gross oil recovery of 585Million barrels of oil (MMBO) over the full life of the field.

This resource position, the partners say, “is supported by external international auditors Gaffney Cline Associates (GCA), who have issued a Competent Persons Report (CPR) and confirmed the life of field resource position of 585MMBO”. 

Charles Keter, Kenya’s Cabinet Secretary for Energy & Petroleum

The key changes to the development concept have been driven by: 

1. Incorporating the production data from the Early Oil Pilot Scheme (EOPS) where 450,000 bbls were produced from Amosing and Ngamia fields. These two fields account for over 50% of the resource distribution, leading to greater confidence in achieving the higher end of the resource distribution range.

2. Optimising the number of wells to be drilled with drilling initially at the crest of the fields to achieve First Oil. Changing the producer to injector ratio from 2:1 to 1:1 leading to improved pressure support and higher resources recovered from the reservoir. 

3. Adding the Ekales field into the first phase of production. Ekales is geographically straddled between the Twiga and Amosing fields and ongoing technical work has helped mature our understanding. 

As such, the first phase will now include the Ngamia, Ekales, Amosing, and Twiga (NEAT) fields and will target 390MMBO of the overall 585MMBO. 

4. Optimising the overall development cost with a facility design capacity of 130,000BOPD and an increase to the pipeline size from 18” to 20” to handle the increased flow rates. 

Total gross capital expenditure (capex), which covers both the upstream and the pipeline to First Oil, is expected to be c.$3.4Billion. 

The increase in capex from the previous design is due to a bigger facility processing capacity, additional wells to be drilled, and larger diameter crude oil export pipeline, which delivers a 30% increase in resources whilst lowering the unit cost to $22/bbl (previously c.$31/bbl). 

The revised concept also allows greater flexibility in adding additional fields into production without significant modifications to the project’s infrastructure.

Tullow Oil, Largest Operator in Ghana, Declares $93Million Profit After Tax

Tullow Oil, the London-listed independent that runs the largest oilfield operations in Ghana, has declared a profit after tax of $93Million for the First Half of 2021.

Most of the money was made from the proceeds of crude oil production from the West African country.

“The start of drilling in Ghana is one of the most tangible examples” of the significant achievements made during the period, the company explains.

Tullow’s gross (operated) production in Ghana averaged c.107,000Barrels of Oil Per Day (BOPD), with c.70,600BOPD(net: c.25,100BOPD) from the Jubilee field, “slightly ahead of expectations due to good facility uptime and well performance”. Gross production from the TEN fields averaged c.37,000BOPD(net: c.17,400BOPD).

Working interest production from Ghana averaged c 42,500BOEPD in 1H 2021, three times the WIP from Gabon (c.14,800BOEPD). Overall Group working interest production averaged 61,230 BOEPD, with Equatorial Guinea and Cote d’Ivoire contributing 2,100BOEPD and 1,800BOEPD respectively. 

Operating costs during the period averaged $12.9/bbl, “a year-on-year increase primarily due to lower production and increased costs related to extended COVID-19 operating procedures”.

Tullow reports underlying operating cash flow of $218Million and free cash flow of $86Million during the period and congratulates itself on reduced administrative expenses of $23Million in 1H 2021, “down c.50% year-on-year”. 

The company’s spent $101Million on capital investment and $37Million on decommissioning.

But its net debt at 30 June 2021 was around $2.3Billion, it says, with gearing of 2.6x net debt/EBITDAX; and “liquidity headroom and free cash of $0.7Billion. 

Tullow says it completed a comprehensive debt refinancing with $1.8Billion of five-year Senior Secured Notes issued and a new $500Million revolving credit facility.

Final Edits Hold Up Release of NNPC’s Full Audited Accounts

Some process bottlenecks are preventing the Nigerian National Petroleum Corporation (NNPC) from releasing the full, detailed audited accounts for 2020 until late Friday, September 3, 2021, or Monday, September 6, 2021. 

Ranking sources at the state hydrocarbon firm tell AfricaOil+Gas Report that the publication of the audited accounts was shifted from Tuesday, August 31, 2021, to September 3 or 6, 2021 “because we had to be sure that every little error is spotted and cleaned up”. 

NNPC’s full audited account for 2020 has been widely anticipated since President Muhammadu Buhari announced the headline earnings on August 25, 2021, especially with the claim that the company made a profit after tax of ₦287Billion, and it was its first profit in 44 years. 

BusinessDay, the country’s top financial daily, claims that its fact-checking reveals that NNPC reported a profit of ₦111.59Billion, in 2017. But the newspaper did not say whether those figures were fully audited. Then again, BusinessDay’s report is clearly a counterpoint to NNPC’s claim that its first audited annual report since its creation in 1977 was released in 2019, for the full year 2018. The corporation has also stated that the second annual audited report, released in 2020, was for 2019.

Part of the query trending on social media is how the corporation moved from a loss of ₦803 Billion in the year 2018 to a loss of ₦1.7 Billion in the year 2019 to a profit in 2020- a year of lower crude oil prices and lower crude output- and how it seemed to have zoomed to its first profit in 44 years when it never reported an audited account until 2019?

There are allegations that the ₦287Billion PAT “is actually a retention of 20% of the profits and dividends paid by independent entities,  which the NNPC received on behalf of the federation (Federal Government of Nigeria, States, and Local Government Areas)”. 

NNPC spokespersons would not respond to these insinuations, and even our sources would not volunteer answers, but they insist: “wait till the report is published, then you can analyze all you want”.

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