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It’s Certain: A 450MW Gasfired Power Plant Will be Built in Temane, Mozambique

UK based power developer Globeleq has announced the Final Investment Decision on the proposed 450 MW gas-fired power plant to be sited in gas rich Temane, in Mozambique’s Inhabane district.

The plant, costing $652.3Million and scheduled for completion in 2024, will be debt financed by IFC, together with its Emerging Africa Infrastructure Fund ($253.5Million), US International Development Finance Corporation (DFC) (approximately providing $191.5Million) and the OPEC Fund for International Development (OPEC Fund) ($50Million). The Multilateral Investment Guarantee Agency (MIGA) has provided up to $251.3Million in political risk insurance to the private sector equity investors.

Located at Temane in Inhambane Province, the Central Termica de Temane (CTT) power project will supply power to the power utility Electricidade de Moçambique, E.P. (EDM) under a 25-year tolling agreement. CTT is expected to provide electricity to meet the demand of 1.5Million households and will contribute about 14% of the electricity supply capacity available to meet demand in Mozambique.

Full Value Chain

“CTT also anchors a new 563 km high-voltage transmission line (the Temane Transmission Project (TTP)) and secures the first phase of the interconnection of the southern grid to the central and northern grids of Mozambique”, Globeleq says in the release. “This will establish a corridor of electrification and ensure a more stable and secure grid and enable the connection of future renewable generation projects. The TTP is owned by EDM and will be funded using grant and concessional finance provided by the World Bank, Africa Development Bank, Islamic Development Bank, OPEC Fund and the Norwegian Government. Together, the entire value chain (gas development, gas fired power plant and transmission infrastructure) will see an investment of more than $2Billion”.

The British developer says the project “is aligned with the Paris Agreement and will support Mozambique’s longer-term sustainable energy transition to net-zero by 2050. CTT’s flexible technical and commercial configuration allows for a variable supply of baseload and dispatchable power and will deliver complementary power so that Mozambique can maximise renewable energy generation projects on its grid and pursue lower carbon energy development. In addition, the Siemens SGT-800 turbines chosen for the plant can be upgraded to handle high hydrogen content, further reducing the plant’s carbon impact”.

Linda Munyengeterwa, IFC’s Regional Industry Director for Infrastructure, Middle East & Africa, commented: “This is our third power investment in Mozambique, and we remain committed to supporting the sustainable development of the country’s electricity sector”, said

The project will be built by the Spanish contractor TSK, utilising Siemen’s gas turbine technology. “TSK has extensive experience in designing and constructing similarly sized combined-cycle power plants and will leverage their in-country construction experience during the 34-month construction period”, Globeleq explains. “CTT is expected to generate around 830 jobs during construction and 90 permanent jobs during operations. This excludes engineering and other work performed off-site. Mozambicans will be prioritized for jobs during both construction and operations. It is estimated that the project will support the creation of 14,000 indirect jobs and livelihoods when it becomes operational in 2024”.

CTT is expected to provide first power in 2024

 


Gabonese Authorities Approve TOTAL’s Divestments of Non-Operated Assets

TOTALEnergies has erased some more Gabon Assets from Its portfolio.

The French major says it has received the approval of Gabonese authorities and has thus “closed its agreement to divest to Perenco Oil and Gas Gabon the Cap Lopez Terminal and non-operated assets of its 58%-owned affiliate TotalEnergies EP Gabon”.

With this transaction, in an amount of $350 million before final adjustment, TOTALEnergies EP Gabon is divesting its interests in seven mature offshore fields operated by Perenco Oil and Gas Gabon, along with its interests and operatorship in the Cap Lopez oil terminal, to Perenco Oil and Gas Gabon. The divested assets’ production stood at 8,400 barrels of oil equivalent per day for the first three quarters of 2021.

“This transaction is aligned with TOTALEnergies’ strategy to enhance its portfolio by divesting mature, high break-even fields.

The company will now focus on offshore.

“TOTALEnergies EP Gabon is refocusing on its operated offshore assets in the Anguille and Torpille sectors and remains a committed oil industry player in Gabon,” said Henri-Max Ndong-Nzue, President of TOTALEnergies EP Gabon.

 


ENI to Build a 50MW Solar Plant in Angola’s Namibe Province

SOLENOVA, a joint venture of the Italian major ENI and the Angolan state oil firm Sonangol, has reached Final Investment Decision (FID) for the first phase of the Caraculo photovoltaic project, located in the Namibe province in Angola.

The signing of the Engineering, Procurement and Construction (EPC) contract is also in hand.

The plant is expected to start-up in the fourth quarter of 2022. The first phase is 25 MWp (Megawatts at Peak). The planned total capacity of the plant is 50 MWp.

“The Caraculo photovoltaic plant will be an important source of electrical power from a renewable resource in the Namibe province”, ENI says in a release. “It will allow the reduction of diesel consumption for electricity generation, thus reducing the emission of greenhouse gases (GHG) and contributing to Angola’s energy transition”

 


AfDB Allocates a Whopping $25Billion for Green Growth in Cote d’Ivoire

The African Development Bank (AfDB) will inject $25Billion into climate projects and green growth in Ivory Coast. This green financing will help accelerate the level of development and reduce emissions in this West African country by 2025.

The fund is meant to finance climate change adaptation and green growth projects paying for renewable energy, green mobility and smart agriculture, with the target to create 500 000 jobs in West Africa’s third  largest economy.

“The $25Billion support will enable Ivory Coast to meet the challenges of the ecological transition and optimize its share of the 4% that the continent receives from the Global Climate Fund”, contends Charlotte Ako, the AfDB’s Head of Climate Change and Green Growth.

Since the Paris climate agreements were signed in 2015, the AfDB has embarked on promotion of the green economy.

In the event, the pancontinental lender has been investing in renewable energy projects across Africa. It has supported the Nachtigal hydroelectric project in Cameroon, the Alcazar solar photovoltaic (PV) project in Egypt and the Lake Turkana wind farm project in Kenya.

 

 


Shell Will No Longer Be Dutch, AngloDutch, or ‘RoyalDutch’

By Toyin Akinosho

European oil giant AngloDutch Shell is about to drop the prefix AngloDutch or RoyalDutch and simply be Shell.

The name change will happen if the shareholders approve, in full, a special resolution at a proposed General Meeting scheduled for December 10, 2021.

The broad proposal, put forward by the Board of Royal Dutch Shell plc, is for a simplified structure that will establish a single line of shares to eliminate the complexity of Shell’s A/B share structure, and align Shell’s tax residence with its country of incorporation in the UK, where it will hold Board and Executive Committee meetings, and locate its chief executive and chief financial officer.

The proposed structure should enhance the speed and flexibility of capital and portfolio actions, strengthen Shell’s competitiveness and accelerate both shareholder distributions and the delivery of its strategy to become a net-zero emissions business.

Shell has been incorporated in the UK with Dutch tax residence and a dual share structure since the 2005 unification of Koninklijke Nederlandsche Petroleum Maatschappij and The Shell Transport and Trading Company under a single parent company. It was not envisaged at the time of unification that the current A/B share structure would be permanent.

A conventional single share structure will allow Shell to compete more effectively. It will:

  • Allow for an acceleration in distributions by way of share buybacks, as there will be a larger single pool of ordinary shares that can be bought back. Following the start of a $2Billion buyback programme in July 2021, Shell announced in September 2021 that it will return an additional $7Billion to shareholders following completion of the sale of its Permian assets in the United States.
  • Strengthen Shell’s ability to rise to the challenges posed by the energy transition, by managing its portfolio with greater agility.

Reduce risk for shareholders by simplifying and normalising Shell’s share structure in line with its competitors and most other global companies. The current complex share structure is subject to constraints and may not be sustainable in the long term.

Following the simplification, shareholders will continue to hold the same legal, ownership, voting and capital distribution rights in Shell. Shares will continue to be listed in Amsterdam, London and New York (through the American Depository Shares programme), with FTSE UK index inclusion. It is fully expected AEX index inclusion will be maintained. Shell’s corporate governance structure will remain unchanged.

Shell is proud of its Anglo-Dutch heritage and will continue to be a significant employer with a major presence in the Netherlands. Its Projects and Technology division, global Upstream and Integrated Gas businesses and renewable energies hub remain located in The Hague.

Shell’s growing presence in wind projects off the Dutch coast, recent decision to build a world-scale low-carbon biofuels plant at the Energy and Chemicals Park Rotterdam, plan to build Europe’s biggest electrolyser in Rotterdam, and its intention to participate in the Porthos carbon capture and storage project, all underline the importance of the Netherlands to the company’s energy transition activities.

Carrying the Royal designation has been a source of immense pride and honour for Shell for more than 130 years. However, the company anticipates it will no longer meet the conditions for using the designation following the proposed change. Therefore, subject to shareholder approval of the resolution, the Board expects to change the company’s name from Royal Dutch Shell plc to Shell plc.

 

 

 


OML 11 is the Biggest Asset in NPDC’s Portfolio

The Oil Mining Lease OML 11, novated to the Nigerian Petroleum Development Company NPDC by the parent company Nigerian National Petroleum Corporation (NNPC), is considered the largest asset, in value terms, in the portfolio of NPDC, in the opinion of several members of the company’s management.

“It has over 11 flowstations and the Ogoni Bodo field is largely untapped, NPDC managers say.

The export terminal for the crude is at Bonny, although Shell didn’t agree that the terminal is part of the OML 11 asset. At $3.5Billion, the value of investment committed to, in the Finance and Technical Service Agreement (FTSA) is the highest of the three FTSAs….Click here to read full article


Technical Challenges Force a Halt to FAR’s Bambo 1 Drilling in The Gambia

Drilling operations were temporarily halted at 3,216 metres Measured Depth below rotary table after significant fluid losses were experienced in Bambo-1, currently being drilled offshore Gambia by the Australian independent FAR.

“These fluid losses were stabilised in accordance with standard offshore operating procedures, and FAR is now planning to plug and side-track the well to continue drilling to the planned total depth (PTD)”, the company says in a release. Prior to side-tracking and provided hole conditions remain stable, FAR is undertaking a wireline logging programme in the current well bore.

The probe is already close to the ptd, which is 3450metres Measured depth below rotary table.

FAR says that oil indications have been detected in roc cuttings and hydrocarbons have been interpreted across several intervals in the well from LWD (logging whilst drilling) data, but “further wireline logging needs to be completed to confirm the finding”.

The operator is concerned that “the addition of the side-track programme has extended the period of operations which is now expected to be completed by the end of December 2021”.

The well has been designated a “tight hole” by FAR and JV partner Petronas and as such, no information related to depth or formation is likely to be provided during the drilling beyond what is required to meet ASX continuous disclosure obligations.

Market participants should exercise care before transacting in FAR shares until such time as FAR, as Operator of the Joint Venture, makes formal ASX disclosures regarding well results.

FAR estimates that the cost to complete the well will increase from a total of $51.4Million to $61.27Million, an increase of $9.87Million or $4.935M net to FAR.

 


Egypt’s LNG Exports in Full Throttle

By Toyin Akinosho

Egypt is capitalizing on the surge in natural gas prices overseas by exporting the equivalent of around 1.6Billion cubic feet per day (1.6Bcf/d), from its two LNG Terminals. 

“Egyptian gas has played a role in securing Europe’s energy needs … The liquefaction units are now operating at full capacity as we try to maximize our natural gas exports in light of the rise in international gas prices,” Tarik El Molla, the country’s Minister of Petroleum, said on the sidelines of the East Mediterranean Gas Forum ministerial meeting in Cairo.

At least 75 LNG shipments have been shipped so far in 2021 — a huge jump after having only shipped 24 during the whole of last year. As of the second week of November, more than eight gas shipments had departed from Egypt in 4TH Quarter 2021., data from S&P Global Platts indicate.

Egypt’s gas production fortunes slumped in the early to mid-2010s while domestic consumption rose, forcing the country to halt LNG export.

But in late 2015, ENI discovered Zohr, the giant gas field (> 22Tcf), in the deepwaters of the Mediterranean and gradually reclaimed its role as a net exporter of LNG. The country’s total natural gas output currently ranges between 6.5 and 7Bcf/d, Mr. Molla told the EMGF ministerial meeting.


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.

 


‘Egypt About to Be the Most Attractive Investment’ in Apache’s Global Portfolio

The Egyptian Parliament has approved the modernization and consolidation of the country’s Production Sharing Contracts (PSCs) with Apache, the American independent.

Those PSC contracts are agreements with the Ministry of Petroleum and Mineral Resources (MOP) and the Egyptian General Petroleum Corporation (EGPC), but the Parliament and the President have to approve.

The story is important. Apache, a subsidiary of APA Corporation, is the largest crude oil producer in Egypt.

“The PSC now goes to the desk of Egyptian President Abdel Fattah El-Sisi for his ratification, which is the next and final step for the revised PSC terms to take full legal effect”, APA says in a release. “Once this has occurred, APA will provide additional details of the PSC changes and updated guidance regarding the financial impacts of various terms, APA’s revised investment plans and the resulting changes to the near-term production growth profile”, the company explains.

“This is the culmination of nearly two years of work with Egypt’s Ministry of Petroleum and Mineral Resources and EGPC to modernize the economic and operational terms of our PSC. The changes will return Egypt to being the most attractive investment opportunity in APA’s entire global portfolio,” said John J. Christmann IV, APA’s CEO, and president. “In anticipation of the approval, we had already increased our drilling rig count to 11 in 2021. Upon final approval, our investment activity will continue to grow into 2022, returning Egypt to a growing production profile and helping to advance the country’s position as a regional energy hub.”

The new PSC will consolidate the majority of the concessions operated by APA’s subsidiaries operating in Egypt (Apache) into a single new concession, which will account for more than 90% of the company’s gross production volumes in Egypt. The changes simplify the contractual relationship with EGPC and include provisions to create a single cost recovery pool, facilitate increased recovery of prior investment, adjust cost recovery, and production sharing percentages, and refresh the term length of both exploration and development leases. The Apache subsidiary that will become the sole contractor under the PSC is owned by an Apache-operated joint venture owned two-thirds by Apache and one-third by Sinopec.

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