All posts tagged feature

“The Onshore Terminal We’re Building is Like, Another Bonny”-GEIL

Section: In the news · February 17, 2023 · No comments |

By Foluso Ogunsan

Green Energy International (GEIL) moved on to site for the construction of an onshore terminal and export infrastructure, the first by any indigenous E& P company in Nigeria.

The facility will have the capacity to hold 750,000 Barrels of Oil at any time. This is expandable to 3Million barrels of crude.

It is the second phase of oil field development, a project that the company embarked on a few weeks after completing the first phase.

The first phase ended with the completion and hook up of two new wells the company drilled on the Otakikpo field, which has raised production capacity from 5,000Barrels of Oil Per Day (5,000BOPD) to over 12,000BOPD.

“The team has worked extremely hard this year to complete the terminal project design in-house and negotiate more favorable terms with service providers to reduce the overall cost of the project considerably”, says Professor Anthony Adegbulugbe, GEIL’s Chief Executive Officer.

“The development of the onshore terminal and export infrastructure is in line with our corporate strategy of developing and installing an efficient evacuation/export system at Otakikpo, thus reducing overall OPEX dollar per barrel ($/bbl). We also plan to make the Otakikpo field a crude processing and export hub by providing access to fit-for-purpose evacuation and export infrastructure for the several stranded fields in the Eastern Niger Delta area. There are over 20 stranded fields in close proximity to the terminal that will benefit from it.”

Kayode Adegbulugbe, GEIL’s Chief Operating Officer, weighs in: “What we are building (with CAKASA as our contractor) here is a new Bonny Terminal”, adding, “It’s not just for us, it is for the energy security of the country …it took nine months for the design. And our staff worked with CAKASA to make sure that the cost is the cheapest in the world.

Mr. Adegbulugbe references (Shell Plc’s) Bonny Terminal in his speech to give a sense of the scope of the budding GEIL terminal. The Bonny Terminal is the biggest in Africa with a capacity to process and export 1.25Million Barrels of Oil Per Day. It is situated on Bonny Island, 48 kilometres southeast of Port Harcourt, a port town on the edge of the Atlantic in eastern Nigeria.

“In the terminal we have accommodation, administrative area for 120 personnel, office for 120 personnel, and it is expandable. We’re building 23kilometres of pipeline into the ocean, because at the depth, we’ll be at about 25kilometres , that’s the depth at which the export tankers can berth and load. The COO explains that ‘the Green Energy 2026 Story’ as he calls it, “may not have been possible without the impeccable efforts of yet another Nigerian organisation, Fidelity Bank, which structured a loan of $250Million for two phases of our project in record time of less than eight months. This is a most unprecedented feat”.

Nigeria’s a Sizeable LPG Exporter, But Most of its Consumption is Imported

Section: Gas Monetization · February 17, 2023 · No comments |

By Foluso Ogunsan

Chevron and ExxonMobil are still exporting Nigerian produced LPG

Nigeria exported 700,000Tonnes of Liquefied Petroleum Gas (LPG) in 2022, even as it grappled with inadequate local production to satiate domestic demand.

The country consumed 1.4Million Tonnes in the year, out of which 800,000Tonnes were imported, according to data by the Nigeria Midstream Downstream Petroleum Regulatory Agency (NMDPRA).

Only 600,000Tonnes of the 1,4Million Tonnes consumed, was locally produced, NMDPRA says.

As the government scrambles for more domestic LPG output to meet its target demand of 3Million Tonnes for 2023, the question is “why export all that LPG only to import more of the same products”?

One answer is that most of what is locally consumed is Butane, while the variant of LPG that is exported is Propane. The 700,000Tonnes of Propane exports left the country from processing plants run by Chevron and ExxonMobil.

Nigerian authorities aim to reduce all LPG exports to the barest minimum. “We now need those volumes for sure” says Dayo Adesina, Programme Manager, National LPG Expansion Implementation Plan in the office of the Vice President. “Even the Propane is needed for Autogas, power generation and other sources of energy. Obviously, butane is for cooking”.

Local producers of LPG (in 2022) included Nigeria Liquefied Natural Gas (NLNG) Ltd ( ~350,000Tonnes Per Year), Kwale Hydrocarbon Nigeria Limited, KHNL, a subsidiary of Sterling Oil Exploration & Energy Production Co. Ltd (~150,000Tonnes Per Year), NNPC E& P Ltd (Intermittent production from the Oredo field integrated gas plant), Platform Petroleum, (~20,000Tonnes Per Year from Egbaoma gas plant).

Adesina: “We need to know what you’re ready to do, what your challenges are, where we can intervene”

Talks are ongoing with Chevron and ExxonMobil on the modalities of retaining all LPG volumes in country. “It Is the Minister of Petroleum Resources that represents the federal government and I guess the joint venture partner in NNPC Limited as well”, Adesina explains, disclosing that one of the companies was “ready to free up 34,000Tonnes a month, (meaning 408,000Tonnes a year), but then the specification (to convert from Propane to Butane), you need to have a splitter on the receiving end”.

Adesina, himself a keen player in the LPG market and a former president of the Nigerian LPG Association, invited stakeholders for a round table discussion on midstream processing of gas on February 9, 2023. His guests included representatives from some E&P companies, including Seplat Energies, Heirs Holdings, Pillar Oil and First E&P; all of whom he challenged to either include LPG in their (planned or ongoing) gas production mix or boost its production in the mix; NLNG Ltd; Standard Chartered Bank and Africa Development Bank AfDB), two ranking financiers who he sought to convince to put more investment into LPG production; NMDPRA – the regulatory agency focused on LPG market opportunity whose representatives were there to clarify regulatory issues and explain government’s goals; a host of energy consultants including Argus and Energy Culture as well as a Climate Accelerator expert. At the session were two representatives of the Nigerian Bureau of Statistics, one of who canvassed vigorous arguments about incentives for choice of butane over kerosene.

Adesina told his guests: “By the time we leave here we should be able to say we have agreed on a Million Tonnes, 2Million Tonnes, half a Million tonnes, less or more over what we are producing now. We need to know what you’re ready to do, what your challenges are, where we can intervene, who we can bring forward. Anybody we need to bring we can bring; that’s the advantage of government. We know that foreign exchange is a problem, some agencies are also a problem too”.

Son of Rainmaker: An Open Letter to Wael Sawan, Shell CEO

Section: In the news · February 17, 2023 · No comments |

By Gerard Kreeft

Prelude: A (possible) scenario of succession at the Shell top

In the summer of 2021, the Shell Board decided that the then CEO Ben van Beurden had to go. The Shell share was on a downward spiral and the transition message proved stale. What to do? The Board decided that Wael Sawan, then Head of Upstream, would become the Prince in Waiting. In Oct 2021, he was appointed Head of Integrated Gas, replacing Maarten Wetselaar who, at the time, was Head of Integrated Gas and seen as the logical heir apparent of Ben van Beurden. Wetselaar resigned and Sawan became Head of Integrated Gas and then CEO.

Dear Mr. Sawan:

I would like to extend my congratulations on your appointment as Shell’s new CEO. As a fellow Canadian its always good to see a fellow countryman endowed with such a prestigious position. Yet with such a position comes much responsibility, in particular shaping the vision for Shell for much of this century; preparing Shell for a brave new energy world. There are some tough choices to make. At best, radical re-alignments and at worst, simply dissolving the company and giving shareholders an alternative option on how to invest their savings.

Shell’s Current Dilemma

Shell has just announced its highest results of the last 115 years: $40Billion in annual adjusted profit for 2022. Yet investor interest has been muted at best. Shell’s share price has only shown a downward spiral of 17% in the 2018-2022 period. The Dow Jones Industrial Index in the same period: January 2018-December 2022, rose 31%: increasing from 25,295 to 33,147.

Table 1: Stock market prices of majors 2018-2022(NYSE)

Year

Repsol

Shell

ENI

TOTAL

Energies

Chevron

ExxonMobil

Equinor

2018

$17

$43

$69

$35

$58

$128

$87

$23

2022

$16

$35

$57

$29

$62

$179

$110

$36

Note: Values based on January 2018 and December 2022

Results for all of the majors was as follows:

Repsol down 5%

BP down 19%

Shell down 17%

Eni down 17%

TOTALEnergies up 7%

Chevron up 39%

ExxonMobil up 26%

Equinor up 57%.

Also, Shell’s dividend yield is uninspiring: 3.47% as of February 2023. This is much in line with Chevron’s dividend yield of 3.56%, BP’s 3.89% and ExxonMobil’s dividend yield of 3.25%. Yet their dividend yields pale compared to the Green Energy Alliance:

Iberdrola 4.19%

Enel 7.46%

Engie 6.49%

Equinor 8.56%

Ørsted only has a dividend yield of 2.3% but its share price in December 2022 was $93; five years earlier in 10 June 2016 it was $37.

Finally, there is the matter of Shell’s Powering Progress, a three-step plan designed to transform and fully prepare the company for the energy transition:

“Growth pillar includes our service stations, fuels for business customers, power, hydrogen, biofuels, charging for electric vehicles, nature-based solutions, and carbon capture and storage. It focuses on working with our customers to accelerate the transition to net-zero emissions.”
“Transition pillar comprises our Integrated Gas, and our Chemicals and Products businesses, and produces sustainable cash flow.”
“Upstream pillar delivers the cash and returns needed to fund our shareholder distributions and the transformation of our company, by providing vital supplies of oil and natural gas.”

Of particular importance is the third pillar which in Shell’s vision will provide the cash flow to fund its transition and growth. Is this really so? The Shell share price and dividend yield demonstrate that there is little trust in this vision. Leaning and depending on its upstream portfolio to lead the company to a bright new green future is perhaps central to Shell’s dilemma. The share price and dividend yield simply demonstrate that upstream oil and gas is viewed as a sunset industry, perhaps a distant memory of the integrated oil companies of 50 years ago. This pillar is not one to build a green future on.

Shell’s vision is also a testimony demonstrating how little the Green Alliance—Enel, Engie, Iberdrola, and Ørsted–is understood and viewed. What has set these companies apart is that they have created a huge competitive advantage which will be hard to challenge for newcomers. They have moved well beyond simply dabbling in green energy. These companies have become specialists and now moving on to the next level: creating a digital platform on which value does not reside in owning resources but rather in managing data-driven ecosystems. The Green Alliance has essentially borrowed a chapter from Uber, which does not own taxis, or Booking.com, which does not own hotels. They create a digital platform on which value does not reside in owning resources but rather in managing data-driven ecosystems. Some members of the Green Alliance have established new goals, such as CO₂ neutrality by 2040 instead of 2050 to which Shell is pledged.

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

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

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

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

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

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

Table 2: Stock market prices of new energy companies 2018-2022

Year	Enel	Engie	Iberdrola	Ørsted
2018	$5	$16	$7	$49
2022	$5	$14	$12	$93

Enel, the Italian power company has seen its share price remain flat. Engie, the large French energy giant has seen its share price decrease by 12.5%. Iberdrola, the Spanish power company has had an increase of 71% and Ørsted, the Danish power company, has seen its stock soar by 90%.

Annual capital expenditures in the near term, according to Shell, could be in the range of $23-$27Billion. The breakdown of Shell’s capex is not given but all indications are that as in the past the lion’s share will go to its upstream and integrated gas and chemicals. Renewables share is unknown.

Re-inventing Shell

Shell is rebranding itself:

Integrated Gas+ upstream becomes Integrated Gas and Upstream Directorate;

Downstream + Renewables and Energy Solutions becomes Downstream & Renewables Directorate.

Shell indicated that it will reduce its upstream division to nine core hubs—Permian, the Gulf of Mexico, United Kingdom, Kazakhstan, Nigeria, Oman, Malaysia, Brunei and Brazil– and it will do no frontier exploration after 2025. If the rush to the global exploration exit continues to pick up speed, Shell may well have to reconsider its(new)upstream strategy, perhaps going so far as to spin off the upstream division as a separate entity or do a joint venture with other partners.

Shell’s integrated gas division could prove to be its star asset. For example, Wood Mackenzie’s AET-2 Scenario (Accelerated Energy Transition Scenario) predicts that in the following decades, market power will shift from OPEC to the giant gas producers, such as the USA, Russia, and Qatar.

According to AET-2, the “Era of carbon-neutral gas is born. AET-2 would require $300Billion to support Liquified Natural Gas growth globally and $700 billion to support dry gas development in North America.” Given that Shell is the global leader of LNG (liquid natural gas) this is certainly a sweet sound for Shell’s LNG business.

Downstream could also prove to be a key energy transition asset. Shell’s REFHYNE Project, the Rhineland Refinery in Germany, could well become the precedent that the company needs to ensure it becomes the leading supplier of green hydrogen, where hydrogen production is powered by renewable energy for industrial and transport customers. Could the REFHYNE Project be duplicated many times over to ensure that green technology becomes a key ingredient in the energy transition?

Pay attention to Shell’s Pernis refinery in the Netherlands. One of the largest in Europe, Pernis refinery has a 400,000 b/d capacity and a complexity enabling the processing of many different crude types. The site is already deeply integrated with chemicals production and is being transformed into an integrated energy and chemicals park that will deliver low-carbon products.

A key remaining issue is how Shell can reallocate its resources—both financial and technical—and maintain an image of being in control of its energy transition scenarios. Upstream with its huge exploration and development costs is perhaps Shell’s largest impediment to becoming a greener company. Do not be surprised to see Shell’s upstream division find a new home, thus freeing up funding needed for Shell’s energy transition. Shell’s Management must very quickly devise a road map demonstrating how by 2030 integrated gas and downstream and renewables divisions will receive the lion’s share of Shell’s capex.

TOTALEnergies has recently announced that by 2050 the company will be on track to have 50 per cent of its energy mix in renewables + 25% in “new molecules” (green fuels). By 2030, Equinor is pledged to having more than 50% of its capex dedicated to renewables. Will Shell follow?

A final comment: Shell’s inability to convince shareholders of its added value is not so much a climate issue. It is rather the inability of the board to proclaim a clear message—be that wanting to be an oil company or an energy company.

Gerard Kreeft, BA (Calvin University, Grand Rapids, USA) and MA (Carleton University, Ottawa, Canada), Energy Transition Adviser, was founder and owner of EnergyWise. He has managed and implemented energy conferences, seminars and university master classes in Alaska, Angola, Brazil, Canada, India, Libya, Kazakhstan, Russia and throughout Europe. Kreeft has Dutch and Canadian citizenship and resides in the Netherlands. He writes on a regular basis for Africa Oil + Gas Report and is a guest contributor to IEEFA(Institute for Energy Economics and Financial Analysis) based in Cleveland, Ohio, USA. His book ‘The 10 Commandments of the Energy Transition ‘is on sale at https://books.friesenpress.com/store/title/119734000211674846/Gerard-Kreeft-The-10-Commandments-of-the-Energy-Transition

Tanzania’s Domestic Gas Output Leaps Above 200MMscf/d

Section: Gas Monetization · February 10, 2023 · No comments |

Tanzania is slowly but surely adding the figures required to be described as a ranking domestic gas market.

Its 2022 production is a five-year record-for the two assets which deliver the molecules to power plants and industry.

Combined, the Songo Songo gas field and the Mnazi Bay project output above 200Million standard cubic feet per day (200MMscf/d) in the year.

The Orca Petroleum operated Songo Songo field, the older of the two projects, had a roaring year, with 40% surge in output, to 110MMscf/d

Maurel &Prom and partner Wentworth Resources produced 90MMscf/d from the Mnazi Bay and Msibati fields, a project widely known as Mnazi Bay project.

A severe drought, which crimped water levels in the hydropower dams, forced up the usage of gas fired thermal plants and aided the increase in production of natural gas.

Gbenga Komolafe, NUPRC’s CEO, to Speak at the Petroleum Club

Section: PARTNER CONTENT · February 10, 2023 · No comments |

PARTNER CONTENT

The Nigerian engineer Gbenga Komolafe, will be delivering the first of the four quarterly dinner lectures of the Petroleum Club of Lagos for 2023.

The chief executive of the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) will be speaking to the theme Nigerian Upstream Sector: Dialetic of Value Optimisation, Energy Transition and Regulatory Perspectives.

The Petroleum Club, a 16-year-old private club where industry leaders and the technical elite interact, unwind and share ideas on issues concerning the sector, reached out to Mr. Komolafe to deliver the opening dinner lecture.

The event, scheduled for February 16, 2023 at the Civic Centre in Lagos, is “a special oil industry dinner”, declares Austin Avuru, Chairman of the Petroleum club. “We are inviting the entire industry to engage the regulator. We are looking towards a very interactive event”.

The enthusiasm for the meeting is mutual.

NUPRC, on its part, says that its Chief Executive, looks forward to “the opportunity to unveil the Commission’s comprehensive plans to reset and invigorate the industry”.

The NUPRC is a creation of the Petroleum Industry Act(PIA) which was passed in August 2021. The PIA vests enormous powers on the two regulatory agencies, of which NUPRC is one. It also creates a field in which the NNPC is no longer the be all and end all of the industry, but a commercial player that is regulated by both NUPRC and the NMDPRA (Nigerian Midstream, Downstream Petroleum Regulatory Authority). Mr Komolafe’s position, by the spirit of the act, is a very influential one.

Komolafe has a lot on his plate; he is running two bid rounds (one for deepwater asset, the other for natural gas flare sites); he is overseeing drafts of regulations that will govern sectors of the industry that NUPRC regulates, based in the Petroleum Industry Act. His NUPRC has just awarded licences to conclude the 2020-2022 marginal field round. He has taken over at a time when national crude oil output has agressively been heading south.

With a $108Million, 35MW Facility, Globeleq Joins the Geothermal -to- Power Business in Kenya

Section: ENERGY TRANSITION · February 10, 2023 · No comments |

UK based electricity provider Globeleq has awarded a contract for the construction of its first geothermal plant.

Toyota Tsusho Corporation (TTC) is the engineering, procurement and construction (EPC) contractor for the 35 MW Menengai geothermal project in Nakuru county, Kenya. The Japanese service provider also won a long-term service agreement (LTSA) for the project.

The $108Million Menengai project will benefit from financing agreements the company inked with the African Development Bank, the Eastern and Southern African Trade and Development Bank and Finnfund in December. 2022.

Construction is expected to begin during the first quarter of 2023 once financial close has been reached. “Having signed these key project agreements with TTC after achieving a fully committed financing in early January 2023, we will now work with the government of Kenya to reach financial close and start construction as soon as possible,” declares Globeleq CEO Mike Scholey.

Globeleq will operate and maintain the power plant once it reaches commercial operations in 2025. The steam turbine and generator will be manufactured by Fuji Electric.

During the twenty-seventh Conference of the Parties, held in Egypt, in November, the Kenyan and UK governments jointly committed to fast-tracking green investment projects worth KSh500-billion in the country, which included the Menengai project.

The 35MW Menengai is part of the first phase of the wider Menengai complex, which is the second large-scale geothermal field being developed in Kenya after Olkaria.

Steam will be supplied to the project by Geothermal Development Company (GDC), a Kenya government-owned company under a 25-year project implementation and steam supply agreement.

National Disaster: South Africa to Appoint Minister of Electricity

Section: Power Deficit · February 10, 2023 · No comments |

South Africa has classified its electricity supply challenge as a national disaster.

President Ramaphosa declares that a Gazette classifying the severe electricity supply constraint a national disaster has been published by the Department of Co-operative Governance prior to his speech.

Ramaphosa announced, in his State of the Nation Address (SONA) on February 9, 2023, that he would be appointing a new Minister of Electricity in The Presidency “to assume full responsibility for overseeing all aspects of the electricity crisis response.”

“The Minister would focus full-time on ending loadshedding and ensuring that the Energy Action Plan announced in July last year (2022) “was implemented without delay””, the President said, his seventh, since he took power in 2018.

South Africa has suffered, since January 2022 to date, its most severe power cuts since 2008. The crippling power outages have led to a decline in mineral production across all commodities. It is estimated that load shedding costs the economy about $60Million,” says Gwede Mantashe, the country’s Minister of Energy.

Estimates from the South African Reserve Bank (SARB) are that the country loses around 50Million a day at stage 6. The central bank has cut the country’s GDP growth prospects for 2023 to a paltry 0.3% in 2023 on the basis that blackouts have cut two percentage points of growth from the economy.

“At the centre of our current energy challenges is the decline in the energy availability factor from an estimated 75% to 49%”, Mantashe told a Mining Conference in Cape Town in the first week of February 2023.

President Ramaphosa said in the SONA that country’s Auditor-General, would be brought in to ensure “continuous monitoring of expenditure in order to guard against any abuses of funds needed to attend to this disaster”.

The disaster declaration would enable government to implement practical measures needed to support businesses in the food production, storage and retail supply chain, including for the roll-out of generators, solar panels and uninterrupted power supply.

“Where technically possible”, Ramaphosa said, “it will enable us to exempt critical infrastructure such as hospitals and water treatment plants from load shedding. “And it will enable us to accelerate energy projects and limit regulatory requirements while maintaining rigorous environmental protections, procurement principles and technical standards.”

Ramaphosa noted that shareholder responsibility for the state owned power utility, Eskom, would remain with the Public Enterprises Minister and would not be shifted to the Mineral Resources and Energy Minister.

“The Minister of Public Enterprises will remain the shareholder representative of Eskom and steer the restructuring of Eskom, ensure the establishment of the transmission company, oversee the implementation of the just energy transition programme, and oversee the establishment of the SOE Holding Company.”

Ghana Gas Inks “Implementation Agreement” to Construct a 150MMscf/d Plant

Section: Gas Monetization · February 5, 2023 · No comments |

The facility, to be part financed by AFC, will process raw gas with natural gas liquids (NGLs) being fractionated into pure components like propane, butane, pentane and stabilized condensate components from the Jubilee and TEN Fields.

Ghana National Gas Company (Ghana Gas) has finally gotten on course of implementing a decade old plan to double its gas processing capacity from 150Million standard cubic feet per day 150MMscf/d to 300MMscf/d.

On February 3, 2023, it signed a Project Implementation Agreement with its joint venture partners to construct a second Gas Processing Plant (GPP Train 2) at an estimated cost of $700Million.

The gas plant would be sited right next to the first train at Atuabo, in the Ellembele District of the Western Region and is expected to be completed within 24 months.

Benjamin K. D. Asante, the Chief Executive Officer (CEO) of the GNGC, initialed for the Ghana Gas while Hilton John Mitchell, a representative of the Consortium, comprising the Integrated Logistics Bureau Limited, Jonmoore International, Phoenix Park Limited and African Finance Corporation, signed for the rest of the partners.

The construction of a second train gas processing plant with a nominal capacity of 150 million standard cubic feet per day (MMscfd), expandable to 300 MMscfd, to process incremental raw gas volumes from the Greater Jubilee and TEN fields.

The project is part of the GNGC’s strategic development plan and expected to increase the national gas processing capacity to 450 MMscfd.

The new gas processing facility will process raw gas with natural gas liquids (NGLs) being fractionated into pure components like propane, butane, pentane and stabilised condensate components from the Jubilee and TEN Fields.

The lean gas containing methane and ethane shall be tied into the lean gas export from existing GPP Train 1 and delivered into the onshore export pipes.

Some of the components of the GPP Train 2 include the construction of a 150 MMscfd capacity processing plant, expandable to 300 MMscfd, a storage facility, an additional compressor package at Atuabo Mainline Compressor Station and provision of utilities and liquid waste treatment system.

GPP Train 2 is expected improve the output of liquids processed from natural gas to 80% compared to the existing facility, which produced between 40 and 50% of gas liquids.

The Ghana National Gas Company was established in July 2011 as a limited liability company with the responsibility to build, own and operate natural gas infrastructure required for gathering, processing, transportation and marketing of gas.

Valentine’s Day 2023: Who will be my Valentine?

Section: ENERGY TRANSITION · February 4, 2023 · No comments |

By Gerard Kreeft

Valentine’s Day is fast approaching…a time to set your heart throbbing…and perhaps a time to pick a new and exciting partner who can whirl you both to new heights of joy and excitement! If you are a member of the Green Alliance– Enel, Engie. Iberdrola, and Ørsted—it is sure sign that you will be appreciated and loved. These companies are hard to hate. Each of them has already unfolded their green strategies for 2023:

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

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

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

Ørsted: the Danish wind energy pioneer is the world’s No.1 offshore wind farm developer and achieved a record-high operating profit for 2022. Ørsted share price in December 2022 was $93; five years earlier in 10 June 2016 it was $37. By 2030 the company’s goal is to have an installed capacity of 50GW.

These companies have created a huge competitive advantage which will be hard to challenge by the oil and gas sector. This is bolstered by a key conclusion from BP’s 2023 Energy Outlook… “ the desire of countries to bolster their energy security by reducing their dependency on imported energy – dominated by fossil fuels – and instead have access to more domestically produced energy – much of which is likely to come from renewables and other non-fossil energy sources”…

While the oil majors are currenting harvesting the benefits of higher oil prices, they are also looking at possible scenarios on how to maximize their gains and minimize their risks. As we march towards CO₂ neutrality in 2050, the oil majors increasingly are looking for ways to share project risks or simply unload their projects and assets. The fear of maintaining stranded assets is very real.

No where are the risks-rewards scenarios more relevant than the deepwater plays. According to WoodMackenzie deepwater is the fastest growing upstream oil and gas resource: production is expected to hit 10.4MillionBOEPD(barrels of oil equivalent per day) in 2022 and will reach 17MillionBOEPD by the end of the decade.

Below a summary discussion of some of the major African projects which will come in play.

TOTALEnergies

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

Much of the 25% forecasted hydrocarbon budget, proposed for 2050, will be focused on African low-cost, high-value projects, including promising deepwater plays in Southern Africa, squeezing more value out of various African assets to ensure a prolonged life cycle.

A prime example is TOTALEnergies’ Mozambique LNG project, which is expected to cost $20Billion and produce up to 43Million tons per annum. The project is currently on hold because of a security alert.

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

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

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

Question: Currently TOTALEnergies’ capital expenditures for the period 2022-2025 is anticipated to be between $14Billion-$18Billion per year: 50% ($7Billion-$9Billion) on hydrocarbons and only 25% ($3.5Billion-$4.5Billion) on renewables. How will the company produce a sharply reduced hydrocarbon budget, on the way to 2050, develop its Southern Africa deepwater assets and also deliver Mozambique LNG?

Will TOTALEnergies’ deepwater division seek other parties to ensure that its various projects can be delivered without additional risk? The Mozambique LNG project will also require an immense amount of capital and risk to deliver. Will these projects be spun-off as joint ventures to ensure that the 25% hydrocarbon ceiling of 2050 is met?

On the way to 2050 the company has a number of other problems to resolve:

TOTALEnergies’ 31% stake in the Fort Hills Oil Sand Project in Northern Alberta, Canada and its 50% stake in the Surmont Thermal Project also located in Northern Alberta. Recently, TOTALEnergies acquired Teck Resources’ stake of 6.7% in the Fort Hills Oil Sand Project. TOTALEnergies’ total cashflow from these oil sands projects (also called “tar sands”) is approximate $1.5Billion. In 2023 these entities will be bundled and spun off as a separate Canadian company. Why? To ensure the company’s green image is maintained.

The East African Crude Oil Pipeline (EACOP) is proving to be harmful to the company’s green image. Public dissent has been mounting and financial hurdles have yet to be resolved. Continued delays only make the completion of this on-going saga more uncertain. Will this too be spun off as a separate entity?

A key strategy is to decrease its oil production by 40% by 2030. In Angola BP has merged its upstream activities with ENI to form Azule Energy. Could this become a model for other African countries?

BP’s Greater Tortue Ahmeyim (GTA) field in Mauritania and Senegal is one of the few oil and gas projects which the company is developing. For 2023 the company has earmarked up to $7.5Billion for oil and gas projects.

Chevron

The company will spend $3.5Billion, or 70% of its international budget, to continue developing its Tengiz asset in Kazakhstan. The remaining $1.5Billion will be spent elsewhere. This is not promising for Africa, where Chevron has major operations stretched across the continent, including major projects in Nigeria, Angola, Equatorial Guinea, and Egypt. Will Chevron seek buy-ins from other players to maintain its status in Africa?

ENI

A key ENI strategy is developing a series of joint-ventures to ensure that ENI can achieve maximum leverage for its current oil and gas assets. A key example is Azule Energy, Angola, a 50-50 joint venture between ENI and BP formed in 2022 to include both companies’upstream assets, LNG and solar business. Will more joint-ventures follow?

Equinor

Equinor’s has two growth pillars: natural gas and its growing offshore wind portfolio. The company is pledged to spend some $10Billion on oil and gas projects in 2022-2023. Key projects in Africa include the Salah and Amenas gas fields in Algeria, equity oil production of some 120,000BOEPD in Angola, and the Tanzanian Gas and LNG Project. Possibly the Tanzanian Gas and LNG Project could see farm-ins in the future. There is no indication that the company will make other major investments in Africa.

ExxonMobil

The company’s two major projects in Africa include:

Rovuma liquefied natural gas (LNG) project is a 15.2Million tonnes per annum (MMTPA) LNG export facility planned to be developed to liquefy and market gas resources from three reservoirs in the Area 4 block of the Rovuma Basin, offshore Mozambique. Mozambique Rovuma Venture (MRV), a joint venture of ExxonMobil (40%), ENI (40%), and CNPC (20%) is the operator and holds 70% interest in the Area 4 exploration and production concession contract.

The project is currently on hold because of a security alert.

Angola Block 15 Redevelopment Project has to date had 18 discoveries over a 20 year period and is expected to deliver around 40,000BOEPD.

For 2023 the company has stated that its capital investments will range between $23Billion-$25Billion. The company will invest 70% of its capital budget in the Permian Basin(USA), Guyana, Brazil and LNG projects.

ExxonMobil’s presence in Angola will last as long as its Block 15 continues to produce oil and gas, but is not of primary focus to the company. If Rovuma LNG continues to be listed as a security risk, Africa will no longer be a primary energy market for the company.

Shell

Shell Namibia’s Jonker-1 well discovered earlier this year in the deepwater Orange Basin and the previously successful Graff and Rona wells, both confirmed as significant discoveries, have given the company a significant deepwater cluster in Southern Africa. The company has a 45% interest, QatarEnergy also 45% and Namcor 10%.

Question: Given Shell’s green ambitions will it request additional companies to farm-in to reduce project costs? Shell also indicated that it will reduce its upstream division to nine core hubs—Permian, the Gulf of Mexico, United Kingdom, Kazakhstan, Nigeria, Oman, Malaysia, Brunei and Brazil– and it will do no frontier exploration after 2025. What will this mean for Namibia?

Key Takeaways

The elephant in the room is the recurring contradictory theme of the greening of the sector and at the same time the fixation of the hydrocarbon dilemma of ensuring maximum returns on higher oil prices while the party lasts. The Green Alliance– Enel, Engie. Iberdrola, and Ørsted—have their strategy in place. The oil majors face immense challenges.

TotalEnergies wants to reduce its hydrocarbon intake to 25% by 2050 . Yet its presence in the Canadian oil sands and its involvement in the East African Crude Oil Pipeline(EACOP)are proving to be an embarrassment to its green image. Will the company seek joint venture partners to ensure that its deepwater portfolio can be leveraged properly? How long can the company continue talking about its massive Mozambique LNG Project being feasible while the project is on a long-term security alert?

BP’s commitment to decreasing its oil production by 40% by 2030 could be a daunting task. In Angola BP has merged its upstream activities with Eni to form Azule Energy. Could more joint ventures follow?

Chevron is in retreat spending at the most up to $1.5Billion in Africa. Chevron has major operations stretched across the continent, including major projects in Nigeria, Angola, Equatorial Guinea, and Egypt. Will Chevron seek buy-ins from other players to maintain its status in Africa?

ENI: Will ENI continue to pursue a series of joint ventures to ensure that it can achieve maximum leverage for its current oil and gas assets? A key example is Azule Energy, Angola, a 50-50 joint venture between ENI and BP formed in 2022 to include both companies’upstream assets, LNG and solar business.

Equinor: The company is pledged to spend some $10Billion on oil and gas projects in 2022-2023. Possibly the Tanzanian Gas and LNG Project could see farm-ins in the future. There is no indication that the company will make other major investments in Africa.

6.ExxonMobil: ExxonMobil’s presence in Angola will last as long as its Block 15 continues to produce oil and gas, but is not of primary focus to the company. If Rovuma LNG continues to be listed as a security risk, will Africa continue to be deemed an investment market for the company?

Shell: Given Shell’s green ambitions will it request additional companies to farm-in to reduce project costs? Shell indicated that it will reduce its upstream division to nine core hubs—Permian, the Gulf of Mexico, United Kingdom, Kazakhstan, Nigeria, Oman, Malaysia, Brunei and Brazil– and it will do no frontier exploration after 2025. What will this mean for Namibia?

Gerard Kreeft, BA (Calvin University, Grand Rapids, USA) and MA (Carleton University, Ottawa, Canada), Energy Transition Adviser, was founder and owner of EnergyWise. He has managed and implemented energy conferences, seminars and university master classes in Alaska, Angola, Brazil, Canada, India, Libya, Kazakhstan, Russia and throughout Europe. Kreeft has Dutch and Canadian citizenship and resides in the Netherlands. He writes on a regular basis for Africa Oil + Gas Report and is a guest contributor to IEEFA(Institute for Energy Economics and Financial Analysis) based in Cleveland, Ohio, USA. His book ‘The 10 Commandments of the Energy Transition ‘is on sale at https://books.friesenpress.com/store/title/119734000211674846/Gerard-Kreeft-The-10-Commandments-of-the-Energy-Transition

TOTAL’s Dalia FPSO Scheduled for TAM in Late February 2023

Section: In the news · February 4, 2023 · No comments |

Angola’s National Agency of Petroleum, Gas and Biofuels (ANPG), the country’s regulatory agency, has announced a scheduled maintenance of the TOTALEnergies’ Floating Production, Storage and Offloading (FPSO) vessel Dalia, located in Block 17.

“The scheduled shutdown that will take place from February 20 to March 26 2023”, the regulator says in a release, noting that it was providing “the necessary clarification, in view of the inaccuracies circulating in some media”.

ANPG says that the operation will involve more than 500 specialized technicians, including TOTALEnergies’ employees and service providers, observing the high standards of safety, hygiene and environment in force in the oil and gas industry”.

It is unusual for a regulator to go to press to announce an operational plan on behalf of an operator, so should a lot more interpretation be read into ANPG’s statement?

The agency does not respond to press inquiries, but it says this much in the announcement:

“Contrary to what is speculated using sources external to the oil sector, this is actually a preventive maintenance (for that very reason programmed) of the equipment, aimed precisely at guaranteeing its operational efficiency and the reduction of production losses, within the scope of a annual work program, approved by ANPG and the Ministry of Mineral Resources, Oil and Gas (MIREMPET).

“As it is a scheduled stoppage, its impact is already safeguarded in the production projections established by the Angolan authorities with investors that are part of the Contractor Group of Block 17, not affecting the commitments of the supply of Angolan oil in the international market”.

ANPG lectures that “the operating philosophy of oil installations includes carrying out work for the preventive maintenance of essential or critical equipment, with complete or partial shutdown of the installations every four, five or six years, for a period of time that varies from 20 to 45 days. Maintenance includes a whole series of interventions such as replacing parts, equipment for engines, turbines, electrical equipment, control instruments, cleaning, painting, among others”.