French major TOTAL and Irish independent Tullow have entered into an Agreement, through which TOTAL shall acquire Tullow’s entire interests in the Uganda Lake Albert development project, including the East African Crude Oil Pipeline.
The overall consideration paid by TOTAL to Tullow will be $575Million, with an initial payment of $500Million at closing and $75Million when the partners take the Final Investment Decision to launch the project. In addition, conditional payments will be made to Tullow linked to production and oil price, which will be triggered when Brent prices are above $62/bbl. The terms of the transaction have been discussed with the relevant Ugandan Government and Tax Authorities and agreement in principle has been reached on the tax treatment of the transaction.
Under the terms of the deal, TOTAL will acquire all of Tullow’s existing 33.3334% stake in each of the Lake Albert project licenses EA1, EA1A, EA2 and EA3A and the proposed East African Crude Oil Pipeline (EACOP) System.
The transaction is subject to the approval of Tullow’s shareholders, to customary regulatory and government approvals and to CNOOC’s right to exercise pre-emption on 50% of the transaction. “We are pleased to announce that a new agreement has been reached with Tullow to acquire their entire interests in the Lake Albert development project for less than 2$/bbl in line with our strategy of acquiring long-term resources at low cost, and that we have an agreement with the Uganda government on the fiscal framework,” said Patrick Pouyanné, TOTAL’s Chairman and CEO. “This acquisition will enable us, together with our partner CNOOC, to now move the project forward toward FID, driving costs down to deliver a robust long-term project.”
Since April 1 2020 Elisabeth Brinton was appointed Executive Vice President of Shell’s New Energies business, steering the company’s work in power, renewables and lower-carbon technology. According to her Linked-In site, ”this role covers Shell’s work in wind and solar, new mobility options such as electric vehicle charging, and laying the foundation for an integrated lower-carbon power business” .
Brinton is a former Silicon Valley entrepreneur and utility industry veteran… She joined Shell in 2018 from AGL Energy, Australia’s largest integrated energy company, where she was Executive Vice President, New Energy. She “helped to increase adoption of renewable energy, build the world’s first residential virtual power plant and grow and sell a profitable smart metering business”. Brinton also
was previously the Corporate Strategy Officer for PG&E Corporation, the US utility company that specialises in renewables, customer solar, energy efficiency and electric mobility.
She has a monumental task of developing Shell’s renewable energy strategy. The situation is grim, especially from a shareholder’s perspective. Shell’s share price has plummeted. Earnings season is fast approaching and shareholders are anticipating their golden share dividend. Not since WWII has Shell reneged paying out such a dividend. Will it be able to continue this tradition?
The signs are not good. Shell’s cash deficit between 2010 and the 3rd Quarter of 2019 was $22.9Billion, based on a study released by the Institute for Energy Economics and Financial Analysis. The other majors- BP, Chevron, ExxonMobil, and TOTAL- included had similar cash deficits. In total more than $200Billion! With a continued lower oil price, the future scenarios are bleak.
Shell plans to invest $2 – $3Billion a year on its power and low-carbon business compared with an overall spending budget of $30Billion per year between 2021 and 2025.
Prior to the current oil and gas crisis BloombergNEF estimated that investments in renewable energy in the period 2010-2019 was $2.6Trillion. Through 2025, $322Billion per annum would be spent, almost triple the $116Billion invested in fossil fuels. With most E &P budgets locked down future investments in the oil and gas sector look grim.
If there ever is a motivation to move on and recognize that renewables are the new boys on the block the time is now. To think that Shell, who are doing symbolic spending on renewables will survive is also an illusion. Shell continues to give a gold dividend and this will be paid for by debt financing, i.e. redundancies and the selling of more assets. In the meantime the share price continues to sink like a stone.
If you make a net comparison between Orsted, the Danish the Offshore Wind Farm giant and Shell then the following:
Shell’s latest share price (6 April 2020) was US$ 39
In May 2018 the share hit a high of $70
In other words, the share has lost almost half of its value.
Orsted’s share price on April 6, 2020 was $108
Orsted’s share price on July 1, 2016 was $35
In this period of time the share price has tripled, while Shell’s share lost almost 50% of its value.
True the Shell share continues to give shareholders a golden dividend of some 6%. Orsted for the last 4 years has only had a dividend of 1.68%.
Yet the true investment return must surely be seen in the spectacular and continued rise of the Orsted share which has tripled and has only had a small blimp in the current economic crisis. How long can Shell afford this current policy? Simply throwing money at it will not solve the problem. What is missing is a strategic vision…and simply appointing a new EVP for Renewable Energy is too little too late. Shell can possibly choose two options:
Continue on its present course paying out its current dividend and financing this through assets sales and redundancies; or
Become a truly dedicated energy company increasing its new energy budget five-fold to at least $10- 15Billion per year. At the same time decrease the dividend and ensure that the Shell share can gain a true value. Ensuring true shareholder value will depend on creating a renewable business model that meets the requirements of todays’ shareholders.
Since this article was written, Shell has announced its commitment to take significant additional action on climate change, including a commitment to achieve net zero emissions. There’s no clarity, however, on how that commitment is tied to day to day business.
Gerard Kreeft, BA (Calvin University, Grand Rapids, Michigan, USA ) and MA (Carleton University, Ottawa, Ontario, Canada), Energy Transition Adviser, was founder and owner of EnergyWise. He has managed and implemented energy conferences, seminars and master classes in Alaska, Angola, Brazil, Canada, India, Libya, Kazakhstan, Russia and throughout Europe. He writes on a regular basis for Africa Oil +Gas Report.
The African Development Bank has refuted the claims in a news article that it plans to provide financial support to the East African Crude Oil Pipeline Project.
It doesn’t name the medium, nor cite the headline, but says it “strongly refutes the claims in the misleading article, which references a letter by a group of civil society organizations and climate change advocates asking the institution to withdraw from the project due to its potential social and environmental damage”.
The facts, according to AfDB:
The NEPAD Infrastructure Project Preparation Facility (NEPAD-IPPF) has not provided financing to any Private Sector Company for upstream oil or gas pipeline projects in East Africa.
No commitment was therefore made to any party to fund the East African Crude Oil Pipeline Project. The project is not included in the Bank’s lending programme.
The Bank is strongly committed to renewable energies.
Then the bank beats its chest
“It is important to point out that the African Development Bank Group has for more than a decade played a leading role in crafting policies and delivering investments that promote sustainable development practices on the continent, including climate adaptation and resilience.
“The Bank is committed to facilitating the transition to low-carbon and climate-resilient development in African countries across all its operational priority areas”.
Nigeria’s petroleum product marketers, under the aegis of Major Marketers Association of Nigeria (MOMAN), have outlined a comprehensive agenda to take the nation out of the gasoline subsidy regime, which cost around $2Billion to service in the last one year.
The roadmap contains five clear messages, starting with the government divesting the power to increase or decrease petroleum prices, and including calls for annulling the Price Equalization Fund (PEF), discontinuation of Direct sales and Direct Purchase (DSDP) programme, amending the law setting up the Petroleum Products Pricing Regulatory Agency (PPPRA) and inaugurating an open access to foreign exchange to all petroleum product importers.
This radical blueprint of reforms, from one of the several stakeholders in Nigeria’s downstream sector, is contained in a statement by Tunji Oyebanji, Chairman of MOMAN.
In it, the association requests:
A fundamental and radical change in legislation is necessary. The clear and obvious risk is that the country has never been able to increase pump prices under the PPPRA Act, leading to high and unsustainable subsidies and depriving other key sectors of the economy of necessary funds.
Purchase costs and open market sales prices for petroleum products should not be fixed but monitored against anticompetitive and antitrust abuses by the already established competition commission and subject to its clearly stated rules and regulations.
A level playing field. Everybody should have access to foreign exchange at competitive rates to be able to import and sell petrol at a pump price taking its landing and distribution costs into consideration.
Discontinuation of the Direct sales and Direct Purchase (DSDP) programme. All foreign exchange proceeds from all sales of crude be paid into the same pool from which all importers can access foreign exchange at the same rate.”
The Price Equalization Fund mechanism should be discontinued and its law repealed as the cost of administration of equalization has become too high and the unequal application of payments by marketers distorts the market and creates market inequities and unfair competition. Internal equalization has been the practice with diesel distribution and sales since 2010 when diesel was fully deregulated.
The pricing system should allow internal equalisation by marketers which would be both competitive and equitable.
Fuel import should enjoy priority access in allocation of foreign exchange, again through a transparent auditable and audited process of open bidding. Conditions for accessing foreign exchange should be streamlined and specific delays before access imposed unilaterally on the downstream oil industry should be discontinued as being inequitable.”
MOMAN said it was stating its position, in the context of the announcement by Timipre Sylva, Minister of State for Petroleum Resources, that the government would implement a policy of “price modulation”, which means, in MOMAN’s view, that the state will give effect to existing legislation enabling it to set prices in line with market realities through the Petroleum Products Pricing Regulatory Agency (PPPRA) as provided in its Act.
“The clear and obvious risk is that the country has never been able to increase pump prices under this law, leading to high and unsustainable subsidies and depriving other key sectors of the economy of necessary funds”, MOMAN stated.
MOMAN admits that “there is no country or economy where governments do not have the power to influence prices”, however, “Governments use economic tools such as taxes or interventions on the demand side or the supply side of the market and other administrative interventions to influence prices where it needs to”.
“The problem here is that government has retained for itself by law the power and the responsibility to fix pump prices of PMS which is what puts it under so much pressure and costs the country so much in terms of under-recoveries or subsidies when it cannot increase prices when necessary to do so.
”It makes sense to relieve itself of this obligation now when crude prices are low and resort to influencing prices using the same tools it does for any other commodity or item on the market”.
“Our current situation, laid bare by the challenges of Coronavirus to the health of our citizens in particular and and economy of our country in general, demands that we are honest with ourselves at this time. A fundamental and radical change in legislation is necessary.
“When crude oil prices go up, government has always been unable to increase pump prices for socio-political reasons leading to these high subsidies and we believe the only solution is to remove the power of the government to determine fuel pump prices altogether by law.”
MOMAN recommends a legal and operational framework comprising of a downstream Industry operations regulator, the Federal Competition and Consumer Protection Commission (FCCPC) or Competition Commission (for pricing issues) and the interplay between demand and supply which will ensure a level playing field, protect the Nigerian Consumer and curb any market abuse or attempts to deliberately cause inequities in the system by any stakeholder.
“In line with change management principles, consultation and engagement with market players should clearly spell out the path and final destination which is full price deregulation”.
Scan Western news about OPEC from the last few years, and a common observation tends to appear: OPEC had a huge influence on the global oil market back in the day. Now, in the shale oil era, not so much.
I would argue that OPEC can safely state that reports of its death—or dwindling relevance—are greatly exaggerated. In fact, OPEC has been at the center of one of the biggest stories of 2020 aside from COVID-19: a historic deal that resolved the oil price war between Saudi Arabia and Russia.
From 2016 to late March, the two oil powerhouses had been part of a loose alliance of OPEC members and non-member producers known as OPEC+. Its purpose was to stabilize the global oil market through voluntary production cuts. The alliance was a success until early this year, when COVID-19 effectively shut down China’s economy and dramatically reduced its crude oil imports. To restore market balance, OPEC member Saudi Arabia asked OPEC+ member Russia to increase its production cuts. When Russia refused, Saudi Arabia stopped complying with its own production cuts and, instead, started flooding the market with oil. Russia followed suit, and plans to renew the OPEC+ agreement on April 1 were abandoned. Crude oil prices went into freefall, and U.S. shale oil producers started struggling to survive. It didn’t help when COVID-19 began forcing lockdowns around the globe, resulting in plummeting demand for crude and even lower oil prices.
The world was watching closely when Saudi and Russian leaders attended an emergency OPEC/OPEC+ meeting on April 9. After three days of negotiations, OPEC and OPEC+ members agreed to massive production cuts starting with nearly 10 million barrels per day May 1. The cuts, which will gradually decrease, will continue through April 2022. While low demand remains a concern, by stabilizing the oil market, OPEC+ will still provide economic relief and save jobs around the world. Shortly after the product-cut agreement was finalized, exhausted Saudi Energy Minister Prince Abdulaziz bin Salman shared his exhilaration with Bloomberg News. “We have demonstrated that OPEC+ is up, running, and alive.”
Indeed. Both OPEC and OPEC+ are very much alive and as relevant as ever.
A New Era?
Despite the condescending descriptions of OPEC I’ve read in American media coverage, I am seeing signs that U.S. leaders are starting to look at OPEC with newfound respect. Even one of the organization’s most outspoken American critics, President Donald Trump, had generous words for OPEC the evening before its April 9 meeting. “Obviously for many years I used to think OPEC was very unfair,” Trump said during a press briefing. “I hated OPEC. You want to know the truth? I hated it. Because it was a fix. But somewhere along the line that broke down and went the opposite way.”
Then there’s Ryan Sitton of the Texas Railroad Commission, which regulates the exploration, production, and transportation of oil and natural gas in Texas. He responded to the Saudi-Russia oil price war by reaching out to OPEC and proposing statewide oil production cuts. After a one-hour photo call with OPEC Secretary General Mohammad Barkindo, Sitton was invited to attend OPEC’s June meeting in Vienna.
While I applaud Sitton’s initiative, I couldn’t help noticing what a departure it was from America’s usual “OPEC playbook.” U.S. energy policy has been driven by a strong desire to “free” the country’s oil and gas industry from OPEC’s influence. As recently as 2018, the U.S. House of Representatives attempted to pass the No Oil Producing and Exporting Cartels Act (NOPEC) (https://bit.ly/3bpS3h5). Had this harmful bill been approved, the U.S. Attorney General would have been empowered to bring antitrust lawsuits against OPEC and its member countries. The legislation likely would have jeopardized foreign investments in the U.S. oil and gas industry and cost America valuable commercial partnerships.
How dramatically things have changed. Two years after NOPEC was proposed, we had a representative from the powerful Texas Railroad commission offering to work with OPEC to help balance the market.
While it’s unclear whether Texas will cut production, Sitton’s decision to open communication with OPEC is a positive, and I hope other U.S. industry leaders will consider the same. Instead of viewing OPEC as the enemy, dismissing it, or avoiding it, why not learn to understand this important organization and lay the foundation for a productive relationship?
I suggest starting with Amazon’s bestselling book, Billions at Play: The Future of African Energy and Doing Deals, which includes a chapter titled “A Place at the Table: Africa and OPEC.” Yes, the chapter covers the value OPEC membership offers African nations, but its insights are relevant to everyone with ties to the oil and gas industry.
The background on OPEC’s 2016 Declaration of Cooperation is particularly timely. It was that agreement among OPEC producers and 11 non-members that resulted in OPEC+. For the first time in OPEC’s history, member countries agreed to work with non-member countries to stabilize the global oil market after increased U.S. shale oil production triggered low prices. Together, participating countries committed to voluntary production adjustments of 1.8 million barrels per day. Until the extraordinary chain of events set off by COVID-19, the OPEC+ alliance remained firmly in place.
The book also delves into the reasons OPEC membership has so much to offer African oil-producers: strength in numbers and a commitment to unity. “The organization says that every new member adds to the group’s stability and strengthens members’ commitment to one another,” the book explains. “Different perspectives create a rich culture where colleagues can learn from one another, anticipate and respond to the complexity of today’s oil markets, and ultimately, influence prices.”
It’s not always a seamless process, but OPEC continues to achieve those objectives. And as we go forward, this kind of unified approach will remain critical. Most likely, the global oil and gas industry will be forced to deal with the economic impacts of COVID-19 and low oil demand for an unknown period of time. Instead of working at cross purposes, oil-producing countries will need to continue cooperating to find solutions, embrace opportunities, and keep the industry alive.
Wagner is the Chair of the German African Business Forum and the CEO of DMWA Resources, a pan-African energy marketing & investment firm. Worked for Trafigura & affiliated companies in oil trading, responsible for managing trading operations and pursuing pre-financing opportunities in around Africa.
With its widely publicized notification of early termination of the contracts for the jackups Gerd and Groa offshore Nigeria, ExxonMobil has effectively inaugurated the widely anticipated reduction of the Nigerian rig activity.
Gerd and Groa, owned by Borr Drilling, were on locations in Asasa and Oyot fields in Oil Mining Leases (OMLs) 67 and 70 respectively, as of early April 2020.
Now other announcements of terminations of rig contracts by other companies are expected to follow, as market conditions worsen.
The two Borr rigs were under contracts originally committed until April 2021 and May 2021. The contracts for both rigs require 180-day notice for early termination.
Borr, a New York Stok Exchange listed company, says it is in discussions with ExxonMobil with regards to planning the discontinuity of operations.
Nigerian rig activity was at a three year high in January 2020, with 32 rigs in various stages of operations on as many locations.
But the combination of COVID-19 and a price war has, since then, has gutted the hydrocarbon industry worldwide, with cargoes of crude oil sloshing around looking for buyers.
Angola’s LNG plant has dropped in production as a result of reduced amount of natural gas that come from the crude oil platforms that supply it.
It sounds intriguing, but the plant relies entirely on associated gas: natural gas which cohabits in the same reservoirs as crude oil.
ALNG’s production capacity is 5.2 Million Tonnes Per Annum (5.2MMTPA). The train can process up to 1.1 billion cubic feet of natural gas per day,
Diamantino Azevedo, Angolan Minister of Mineral Resources and Oil is quoted by Angolan state news agency Angop, as saying that additional investments are needed in drilling more oil wells in the country, in order to increase the natural gas that is channelled to ALNG plant “to reach the installed production capacity.” The minister reportedly added: “This is a challenge that Angola LNG and the country have to take on, in order to achieve capacity and maintain project stability over a long period of time”.
The immediate challenge to Mr. Azevedo’s wish is the immediate status of Angolan rig count. Angolan rig activity figures had crashed from robust 22 in September 2015 to 4 in August 2018, according to the August /September 2018 edition of the monthly Africa Oil+Gas Report.
Angolan LNG has had its fair share of challenges since it came on line in 2013. Barely a year after commissioning, it faced an extended plant shutdown of more than two years from April 2014 to June 2016 to fix a number of design issues that caused an incident on 10 April 2014
That situation led Chevron, the operator, to create an internal project management system to better track contractors and subcontractors on major projects. Chevron is the largest stakeholder in the facility, holding a 36.4% interest, with partners that include Sonangol, 22.8%, and BP, ENI and TOTAL, with 13.6% each.
Angola LNG has sold its first pressurised domestic butane cargo from its plant in Soyo, the facility built to create value from Angola’s offshore gas resources.
The first cargo was sold to Sonangol Gás Natural Limitada on a Free on Board (FOB) Soyo basis and safely loaded onto the pressurised butane carrier Astrid.
Sales of butane from Angola LNG will be prioritised for the domestic market, with any remaining butane committed for sale – on an FOB Soyo basis – to all of Angola LNG’s shareholder affiliates, for export markets.
The pressurised butane jetty was commissioned immediately prior to commencement of loading operations. Commissioning included the testing of safety devices, mooring arrangements and loading arms. All three jetties (LNG; refrigerated propane, butane and condensate; and pressurised butane) have now been commissioned and used to safely and successfully load cargoes.
Commenting on the first domestic butane cargo Artur Pereira, CEO, Angola LNG Marketing said: “Loading and sale of the first domestic butane cargo marks a further landmark in Angola LNG’s history. This, and future, pressurised butane cargoes will support Angola’s domestic energy needs, to help power the country’s growth and development.”
Angola LNG Limited is an incorporated joint venture between Sonangol, Chevron, BP, ENI and Total that will gather and process gas to produce and deliver LNG and NGLs. The plant has an expected duration of at least 30 years.
First it was the National Planning Commission report. Then came the Cabinet’s lifting of moratorium.
Overnight, the mainstream thinking of the South African political and business elite has changed from “gas-is-not-on-the cards” to “its -okay-to-include-gas-in-the mix”.
The South African National Planning Commission’s revised plan, released in August 2012, repeated its cautionary note on the cost of nuclear power, the country’s preferred alternative to fossil fuels, and suggested a diverse mix of energy sources. The Commission said: “If gas reserves are proven, and environmental concerns alleviated, then development of these resources and gas-to-power projects should be fast-tracked.”
Several days after the Planning Commission’s report was aired all over the media, the government lifted a year- long moratorium on Shale Gas Exploration.
And then, the South African media went agog with discussions about the imperative of gas in the country’s energy mix.
South Africa’s energy policy has not always viewed natural gas, the world’s least polluting fossil fuel, as an important resource for its planned, massive increase in electricity supply capacity.
The Integrated Resource Plan (IRP) for the country, published as a government gazette in May 2011, envisages an addition of 42, 600MW of new build electricity generation capacity between 2010 and 2030, to all existing and committed power plants. The plan assumes a nuclear fleet of 9,600MW; 6,300MW of coal; 17,800 MW of renewable; and 8,900 MW of other generation sources, which includes only 2, 400MW of close cycle gas turbine generated power.
The installed open cycle gas turbines currently generate 1,316MW, or a mere 4% of the country’s nameplate capacity. Two of these four gas plants-the 588MW Ankerlig plant and the 438MW Gourikwa plant- were commissioned only in the last six years. Before they were built, the country was generating just 342MW (171MW each) from two plants: Acacia and Port Rex. South Africa’s power utility Eskom currently supplies 45% of Africa’s power and 95% of its own country’s electricity, mostly from coal-fired plants. There’s limited space for more private sector generation in the medium to the long term.
We have argued, in this magazine, that even the 2,400MW of gas fired electricity in the IRP, a 20 year resource plan envisaging a build of 42, 600MW, is a mere after thought. The national conversation around energy issues in South Africa has involved every conceivable energy source but natural gas. The roll out for installation of renewable energy plants has kicked in; there’s a vibrant discussion of the possibility of scaling up nuclear power generation in the country, even if there are more skeptics than optimists; and the place of coal in the country’s energy future is assured.
But no one was, really, discussing gas until recently. The IRP had extensive input from a wide range of stakeholders in the energy industry.
A key reason for the aversion to gas utilization in S.A’s energy mix is that while the country doesn’t have much gas reserves, it considers the cost of imported gas as rather too high. Take this liner in the plan: “The import coal and hydro options are preferred to local options, but imported gas is not preferred to local gas options”. So, even while South Africa has the opportunity to benefit from the recent natural gas finds offshore Mozambique, one of the most significant hydrocarbon discoveries on the planet in the last 10 years.
The current upbeat mood about gas in the South African national conversation is driven largely by the optimism that Shale gas exploration would unlock trillions of cubic feet of shale gas in the Karoo.
The discussion still has not accommodated nuanced reviews of the opportunities afforded by gas pools in neighbouring countries.
UK OPERATOR, BG HAS MADE THE FIRST delivery of gas from the West Delta Deep Marine concession Phase IV project (WDDM IV) into Egypt’s domestic natural gas market. WDDM IV was sanctioned by the Egyptian government and partners on the project in May 2006 to deliver gas from seven additional deepwater wells in the Scarab/Saffron and Simian subsea fields. BG says that the delivery date was one month ahead of schedule, the project was delivered under budget and with a successful safety record, achieving 2.5 million man hours with no lost time injuries. The project also marks the first time that all subsea structures were fabricated entirely in Egypt by Petrojet, an affiliate of the Egyptian General Petroleum Corporation (EGPC). Ian Hewitt, President of BG Egypt, said, among other things: “This is a great example of sustainable development where BG Egypt, as well as delivering on local content obligations, has also worked to improve the capability of the local contractor.”