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Shale Drilling on the Rebound in 2022, with Spending Cruising to $100Billion

 By Rystad

US shale expenditure is projected to surge 19.4% next year, leaping from an expected $69.8Billion in 2021 to $83.4Billion, the highest level since the onset of the Covid-19 pandemic and signaling the industry’s emergence from a prolonged period of uncertainty and volatility, according to a Rystad Energy report.

As the impact of the pandemic on demand and activity levels out, US Land players are poised to loosen their purse strings. As the Omicron variant of the novel coronavirus tightens travel restrictions and raises concerns over a potential industry slowdown, some hesitancy in spending could yet materialize.

Of the expected year-on-year increase, service price inflation alone is set to add $9.2Billion, with increased activity chipping in $8.6Billion. These increases will be partially offset by $4.2Billion in savings from efficiency gains. Efficiency gains are expected to be driven predominantly by further adoption of simul-fracs. Despite the sizeable annual spending growth, the 2022 total will still end up well below the level forecast for 2022 before the pandemic took hold.

“Oil and gas activity and upstream spending in US Land has been exposed to significant volatility in the last two years. Aggressive strategies from private operators in the US shale patch have driven spending this year, but we anticipate significant growth in 2022 from public and private operators alike,” says Artem Abramov, head of shale research at Rystad Energy.

In November 2019, before the market downturn caused by Covid-19, Rystad Energy forecast total US shale spending for 2020 would be $104.9Billion, with $109.7Billion and $119.8Billion per annum estimated for 2021 and 2022, respectively. The estimate for 2020 was taken down sharply in that year’s second quarter to $60.4Billion following the unprecedented oil price crash and a domestic storage crisis. While modest adjustments to this estimate were observed in the second half of 2020 and the first half of this year, the final numbers for all public producers and final estimates for private exploration and production (E&P) players had only a marginal net impact on that original estimate. Currently, the number for 2020 still stands at $60Billion.

Public independents largely maintained their 2021 US shale budgets compared with 2020 on a full-year basis, with a modest increase in the weighted-average well activity index (two-thirds of completion count and one-third of drilled well count). Somewhat higher activity was offset by structural efficiency gains and lower service costs behind actual drilling and completion (D&C) operations. While the latter might sound counterintuitive from the perspective of significant spot rate inflation in most service segments throughout 2021, it should be noted that there was an opposite trend throughout 2020, which allowed large independents to lock in cheaper service rates in early 2021 compared to what was behind their D&C spending in 2020.

Meanwhile, private operators, which moved aggressively throughout 2021, warmed up spot service rates and have already felt the impact of cost inflation this year. As a result of this private E&P activity uptick, total US shale capital expenditure increased by around 16% in 2021 compared with 2020.

How the regions stack up

At the regional level, spending in the Permian and Haynesville plays stayed resilient during 2020’s downturn, seeing a faster structural increase in activity this year. As a result, full-year upstream spending in these regions has increased by between 23% and 24% so far this year, outperforming the national average growth rate. The Niobrara saw an even steeper increase in spending in 2021 on a percentage basis, albeit starting from a particularly low base after the massive collapse last year.

Appalachia and the Eagle Ford, on the other hand, have experienced only minor growth in 2021, with spending rising between 3% and 6% compared with last year. While the Eagle Ford has seen a healthy recovery in rig count during 2021, its full-year spending growth numbers were dragged down by low drilled but uncompleted (DUC) wells to completion activity, especially when compared to the Permian, and inflated 2020 spending amid robust activity in the first quarter of 2020. Spending in the Bakken and Anadarko regions in 2021 has declined by between 7% and 14% from last year.

Looking ahead to 2022, the Eagle Ford, Niobrara and Anadarko regions are anticipated to beat nationwide average spending growth due to the rig activity expansion observed in recent months, which provides some momentum to the increase in the running rate of frac activity in 2022. The Bakken is forecast to have 19% spending growth next year, matching the national average growth rate, while the Permian is set to grow by 17%, slightly less than the national average as other basins are catching up. On the gas side, we anticipate a 15% increase in spending from Appalachia and an around 10% increase in the Haynesville. While the full-year growth rate is seen higher in Appalachia, this does not really suggest a stronger increase in the running rate of frac activity in the northeast region, where supply remains constrained by the takeaway capacity situation.

 


bp Commences Oil Output From Angola’s Platina: Planned Peak is 30KBPD

bp Angola’s Platina project in Block 18 has started production. The project was brought online both ahead of schedule and under the contractor group’s initial budget. Angola’s National Agency for Petroleum, Gas, and Biofuels (ANPG) considers the project a significant reinforcement of Angola’s oil production capacity.

Platina is a subsea tie-back development to the existing Greater Plutonio floating production, storage, and offloading (FPSO) vessel on Block 18.  It will access an estimated 44 million barrels of oil reserves and, at peak, is expected to add 30 thousand barrels of oil per day to Block 18 production. The project was delivered 44 days ahead of schedule and 25% below the original budget. Its development increased expected recoverable resilient reserves by 10%. The development of resilient hydrocarbon resources focused on maximizing value from existing positions and on high-quality fast-payback new projects is central to bp’s strategy.

Belarmino Chitangueleca, Acting Chief Executive Officer of ANPG highlighted the importance of Platina’s first oil in Block 18 and its contribution to oil production levels in Angola: “With this and other projects, we are gradually meeting the objectives of preventing production decline and increasing production levels with the ongoing bidding of projects.”

Platina, the development of which was approved in December 2018, is the first new development on Block 18 since Greater Plutonio started up in 2007. It is bp’s first newly operated development in Angola since the start of production from the PSVM development in Block 31 in 2012.

Platina is the seventh new project to start production for bp worldwide in 2021. It follows new projects in Egypt, India, Trinidad, two in the US Gulf of Mexico, and an earlier project on Block 17 offshore Angola.

bp Angola is the operator and has a 46% stake in Block 18, Sinopec has a 37.72% stake and Sonangol P&P 16.28%.​


Last Man Standing: In Praise of a Vanishing Era

By Gerard Kreeft

 

 

 

 

 

 

With a shrinking oil and gas market, it is perhaps a sign of the times when two of the most respected and deeply devoted drilling contractors decide to forego their independence and instead merge their operations. A story of technical prowess, innovation and adaption to market pressures in order to survive. The story of Maersk and Noble Drilling.

The Maersk Saga

 

 

 

 

 

The Maersk dynasty dates four generations. Captain Peter Mærsk Møller (1836-1927) took part in one of the most significant changes in shipping; the move from sail to steam in the late 1800s. He obtained a position in Jeppesen Shipping, a leading Danish shipowner. He captained various Jeppesen vessels and married Anna, the owner’s daughter. Later a steamship company was formed, the foundation of A.P. Moller-Maersk.

 

 

 

 

 

A.P. Møller (1876-1965), became the second generation, acquiring the company’s first five tankers in 1928 and established offices in the USA, the UK, Thailand, Hong Kong and Indonesia. Later he was awarded an offshore concession for mineral exploration, which became the basis of Maersk Oil and Gas and which was later sold to TOTALEnergies.

When A.P. Møller, passed away in 1965 his son Maersk Mc-Kinney Møller assumed chairmanship of the family foundations. Currently Ane Mærsk Mc-Kinney Uggla, the youngest daughter of Emma and Mærsk Mc-Kinney Møller, became chairmanship of the family foundations with the passing of her father in 2012.

 Maersk Drilling

The Maersk Drilling chapter is one of innovation and technical prowess. Maersk Drilling traces its origin to the Danish Underground Consortium (DUC), established by Maersk, Shell and Gulf (now Chevron) to explore the concession granted to Maersk. The Maersk Storm Drilling Company was set up in joint venture with the Dearborn Storm Drilling Company. The two semi-submersibles named Zephyr I and Zephyr II were owned by Maersk but operated by Storm Drilling.

Later Maersk Drilling established Atlantic Pacific Marine Corporation (APMC) in the USA. APMC served as a basis for building knowledge concerning drilling technology. This eventually led to the construction of the jack-up Maersk Explorer in 1975, the world’s largest jack-up. Shortly after Maersk Drilling ordered 5 additional rigs: 2 jack-ups, a semi-submersible, a drilling tender, and a so-called self-contained platform rig.

In 1990 Maersk Drilling pioneered the foundations of the jack-up market off the Norwegian Continental Shelf. Until then the NCS had primarily been explored and developed by semi-submersible rigs.

Between 1990-2004 Maersk owned and operated 10 cantilevered offshore barges on Lake Maracaibo in Venezuela.

In 2008 Maersk entered the deepwater market with the delivery of the Maersk Developer and subsequently the Maersk Discoverer and Maersk Deliverer. An additional four drillships were delivered in the period 2011-2015.

In 2019 Maersk Drilling was listed as an independent company on the Copenhagen Stock Exchange.

Noble Drilling

Noble Drilling finds its origins in Oklahoma. When oil was discovered at the Lloyd Noble family farm, this set-in motion the basis for the founding of Noble Drilling. In the 1920s with the discovery of the Seminole oil field, which produced 527,000 barrels of oil per day, Noble Drilling soared.

Originally the company consisted both of drilling and oil and gas properties; the latter became Noble Energy and was purchased by  Chevron for $13 billion in 2020.

In the 1990s Noble Drilling upgraded five rigs limited to working in 70 feet of water or less to units capable of operating in water depths of 6,000 feet or more. In 1997 the Noble fleet included 45 rigs.

Between 2000-2020 Noble augmented the fleet by adding high specific assets and developing strategic alternatives for many existing standard specifications, transforming Noble, one of the oldest drilling contractors, with one of the youngest fleets in the industry. This includes 17 new rigs to the fleet through acquisitions and new builds and the departure of 34 jack-ups, 5 drillships and 3 semi-submersibles.
 Conclusion

The new combination-Maersk and Noble Drilling-could prove to be awesome competition. A strong, virtually debt-free balance sheet and one of the youngest fleets in the industry.

 

 

 

 

 

 

The last word can best be told by what a former Maersk employee told me, only half-jokingly: “the 7 stars of the Maersk logo means that Maersk employees have to work 7 days a week”.

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). His book entitled The 10 Commandments of the Energy Transition, is scheduled for publication in early 2022.


TOTAL: First Oil in Uganda in 2025, First Gas in Mozambique in 2026

TOTALEnergies has announced the proposed dates for commissioning of its two ongoing hydrocarbon field development projects in East Africa.

The company’s Tilenga project, which monetises a cluster of onshore fields the company is developing in Uganda, is expected to reach first oil by 2025, according to TOTALEnergies Strategy Outlook 2021. The French major does not say there are any complications in delivering the project which, along with CNOOC’s Kingfisher field development, is a 230,000Barrels of Oil Per Day (BOPD) project, ferried to the Indian Ocean though a 1,400km pipeline.  TOTALEnergies notes, however, that the entirely onshore project is delivered in a sensitive environmental context and with a significant land acquisition programme.

In Mozambique, the French Supermajor has postponed the likely date for the first cargo of Liquefied Natural Gas expected from the Area 1 project from 2024 to 2026. The company does not say anything about insurgent attacks, which, primarily, was the reason for the setback.

 


AfDB Grants Mozambique Some Minuscule Funding to Boost Local Content

The African Development Bank Group says it has approved a grant of $1.5Million to Mozambique to boost the development of local content “in the natural resources sector”.

The money looks rather minuscule, but the continental lender says it “is earmarked for Small and Medium-sized Enterprises (SME) targeting local content and women-owned business in the natural resources sector of the nation”.

An AfDB press release says that the new approval brings its total commitment to SME Development to $2.5Million, following an announcement of a previous financial package of $1Million in June 2021 to the Instituto para a Promoção das Pequenas e Médias Empresas (IPEME) under the Local Content Development Project for Youth-Led and Women in Business MSMEs (MOZYWEB). IPME is funded by the Youth Entrepreneurship and Innovation Multi-Donor Trust Fund (YEI MDTF) (https://bit.ly/3wPvrCj).

The new financial contribution approval, from two Bank fund sources –  the Affirmative Finance Action for Women in Africa (AFAWA) (https://bit.ly/3wSuppd), through the Women Entrepreneurs Finance Initiative (WeFi) (https://bit.ly/3kGJghD), and Fund for African Private Sector Assistance (FAPA) (https://bit.ly/3Hlnh9D) –  will provide technical and institutional assistance to Empresa Nacional de Hidrocarbonetos (ENH), ‘Mozambique’s national oil company under the LinKar Initiative.

This support follows the Board of Directors approval of a $400Million senior loan project in November 2019 to “Mozambique LNG Area 1.”  The loan agreement carried a recommendation to build capacity in developing local companies by specific technical assistance programs in order to create decent jobs in the country.

The LinKar Initiative will focus on upgrading the capacity of local SME suppliers of goods and services in a wide variety of sub-sectors, including catering, office supplies, training, facilities management, customs, recruitment, and logistics, with the aim of advancing the country’s economy.

Estevao Pale, CEO of the Empresa Nacional de Hidrocarbonetos (ENH),, said: “The implementation of gas projects, foreseen in the next 12 to 24 months, of the Coral Floating LNG and Area 1 (by TOTAL), in the Rovuma Basin, as well as the construction of the Central Termica de Temane ( CTT)  project,  calls for an urgent materialization of LINKAR’s four areas of action: capacity-building, funding, technical assistance and hiring of SMEs”.The CTT project is projected to generate an average of 450MW of power and the production of 30.000 tons of LPG (domestic gas), in the Inhambane Basin”.

ENH is the government body responsible for exploring, producing, and commercializing hydrocarbons in Mozambique, is committed to leveraging Mozambique’s gas resources to drive broader economic growth and create sustainable local jobs.

Mr. Ple says that both programmes (LinKar and MOZYWEB) “will support more than 300 local companies by providing them with access to skills and certification, access to contracts and financing from local financial institutions. These SMEs will create decent jobs, especially for women and youth, and boost local content in the gas industry in Mozambique”, African Development Bank Country Director Cesar Augusto Mba Abogo, said, commending the Bank Group’s support to Mozambique”.

 

 

 

 


Libya Knocks Angola to Third Place African Oil Producer

Libyan crude oil output averaged 1.163Million Barrels Per day in August 2021.

It hardly bettered Angolan figures, which made 1.129MMBOPD in the same month.

But it’s not difficult to envision the North African country edging out Angola and becoming the continent’s second largest crude oil producer after Nigeria.

Between January and August 2021, Libyan crude oil output has ranged between 1.13MMBOPD and 1.195MMBOPD, with the average being 1.1615MMBOPD for the eight-month period.  Angolan numbers have trended lower, ranging between 1.073MMBOPD and 1.176MMBOPD. Angolan average output in that period is 1.127MMBOPD.

These figures may appear too close-less than 40,000BOPD- to declare that Libya has surpassed Angola in crude oil output, but Libya is coming from a low base; a situation created by conflict.

Whereas it had not, in those eight months, returned to the 1,213MMBOPD high that it made in November 2020, it has shown significant hunger and considerable headroom to grow.

Libya’s security issues loom menacingly in the background, threatening its output and there is hardly enough money to deliver on field optimization and basic day to day operations.

But Angola doesn’t suffer the scale of these challenges that Libya confronts.  Apart from investment fatigue, which also affects Libya, the Angolan problem is almost squarely about geology. With proven reserves less than 10Billion barrels, it hardly has the hub sized reservoirs in enough quantity to view a line of sight to, say 1.5MMBOPD by 1H 2022.

Libya meanwhile, is all of a 44Billion barrel oil tank, the largest repository of crude on the continent. Years of under investment caused by both a peculiar brand of politics as well as conflict, have, however stifled exploration, development and field optimization. But Libya has managed to add more than 1 Million Barrels of Oil Per Day since September 2020, after its two warring factions — the UN-backed Government of National Accord and the self-styled Libyan National Army — agreed to a peace deal. And now the state hydrocarbon company says it is sure of ” producing 1.45MMBOPD by the end of 2021, if it gets the budget and the country is better secured. Just two fields can deliver the 300,000BOPD that will take the country to that goal: one in the Sirte basin and the other in Ghadames Basin.

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Was the NNPC Operationally Profitable in 2020?

While the Nigerian state hydrocarbon firm congratulated itself on making a net profit after tax for the first time in its 44-year history, Africa Oil+Gas Reports examination of the audited reports of each of its 21 subsidiaries indicate that Nigeria’s most integrated oil and gas company struggled with revenues in 2020, operationally, in the entire value chain, than it did in 2019.

There was a depressing upstream showing, a midstream failure and a mixed bag of fortunes in the downstream.

Even the supposedly bespoke investment vehicles: for the investment firms (NAPIMS, Duke Global Energy) performed…

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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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