The Italian player ENI has signed an agreement with the Egyptian General Petroleum Corporation (EGPC), committing to spending a minimum $1Billion on exploration and extraction in the Gulf of Suez and Nile Delta regions, the country’s Oil Ministry says in a statement, which does not specify a timeframe.
Tareq Al-Mulla, Egypt’s Minister of Oil and Mineral Wealth, and Alisandro Politi, ENI’s Executive President of Natural Resources Activities signed the agreement “of commitment to search for oil and development and exploitation in the Gulf of Suez and the Nile Delta between the Oil Corporation and Eni Italian Company and issued under law No. 185 for 2021”, the statement says.
ENI is also committed to spend at least $20Million extra dollars to Drill four (4) wells, “and the agreement comes within the new curriculum of the Ministry of Oil and Mineral Wealth to increase production rates and countering the natural shortage of energy by using the latest technologies in some areas are currently producing”, the statement, translated from Arabic says.
Egypt and ENI have lined up a number of joint initiatives on carbon capture, utilization and storage (CCUS), to be announced during the upcoming COP27 global climate summit in Sharm El Sheikh next year. Carbon capture is expected to be a big theme at COP27, with Oil Minister Tarek El Molla stressing its importance to the oil and gas industry and to combating climate change
Sirius Petroleum reports that it has now executed a legally binding Master Services Agreement with Baker Hughes relating to the development of the Oil Mining Lease (OML) 65 in Nigeria’s Niger Delta. “This follows the Memorandum of Understanding (MOU) signed with Baker Hughes Company Limited earlier this year”, the London headquartered company says.
The MSA formalizes the terms of the appointment of Baker Hughes as the approved services provider to Phase 1 of the approved work programme (AWP) of the OML 65 Licence, a large onshore block in the western Niger Delta, Nigeria. Baker Hughes will provide a range of drilling and related Integrated Well Services under a mutually agreed pricing structure to deliver the initial nine well programme to Sirius and the joint venture COPDC Petroleum Development Company Limited (COPDC) in which Sirius is a 30% shareholder.
Phase 1 of the AWP will focus initially on the redevelopment of the Abura field, involving the drilling and completion of up to nine development wells, intended to produce the remaining 2P reserves of 16.2 MMbbl, as certified by Gaffney Cline and Associates (“GCA”) in a CPR dated June 2021.
The execution of the MSA with Baker Hughes constitutes the fulfilment of a key condition precedent to the drawing of the first tranche of funds under Sirius’ senior secured prepayment facility as the first stage of the OML 65 development programme, announced earlier this year.
“This marks a significant milestone for Sirius and its operational partners, and we look forward to working with the team on this innovative project.” said Toks Azeez, Sales & Commercial Executive for Subsaharan Africa at Baker Hughes. “Our leading Integrated Well Services solutions leverage new digitalization capabilities and will help deliver cost effective and efficient operations for the development of this important onshore opportunity.”
Ghana’s oil and gas sector scored 78 out of 100 points in the 2021 Resource Governance Index (RGI), improving by 11 points since the 2017 RGI.
Strengthened resource governance is underpinned by improvements across both the index’s value realization and revenue management components.
• Ghana’s oil and gas sector’s move into the “good” performance band in the 2021 RGI is driven by improvements in the governance of licensing and national budgeting along with continued improvements of the state-owned Ghana National Petroleum Company (GNPC) and the Ghana Stabilization Fund, the country’s sovereign wealth fund.
• Adoption of new laws regarding licensing and national budgeting strengthened Ghana’s extractives legal framework and helped drive the 2021 RGI score increase.
• Both law and practice scores increased, but the difference between them widens from -7 to -22, signaling a worrying “implementation gap.”
• GNPC improved its performance through commodity sales disclosures, but areas for future improvement include the timeliness of disclosures and aspects of corporate governance.
• The Ghana Stabilization Fund scored a full 100 points on governance, owing to new disclosures of assets and asset classes.
• Ghana’s oil and gas sector outperformed the older gold mining sector owing to enhanced transparency and accountability in the oil and gas sector legislative framework.
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.
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.
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.
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 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.
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”.
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.
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 Report’s 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…
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.