It’s possible that I shall make an ass of myself. But in that case one can always get out of it with a little dialectic. I have, of course, so worded my proposition as to be right either way (K.Marx, Letter to F.Engels on the Indian Mutiny)
Friday, February 23, 2024
Ghana LNG Import Terminal Nearing Finish Line—and None Too Soon
Ghana’s much-delayed natural gas import terminal is nearing the finish line and is expected to be complete by the end of this year, the country’s oil regulator said on Tuesday.
The LNG pipeline and storage network and import terminal, owned by Tema LNG Terminal Co., is already years behind. Ghana’s National Petroleum Authority CEO Mustapha Abdul-Hamid said on the sidelines of an energy conference in Cairo that Ghana had signed a gas supply agreement with Equatorial Guinea LNG, majority-owned by Marathon Oil Corp, Sonagas, and Marubeni.
Ghana has transitioned itself into one of the fastest-growing producers of hydrocarbons in Africa. In 2022, Ghana was suffering from its worst economic crisis of this generation, plagued by runaway inflation, a depreciating currency, sky-high energy tariffs, and a long list of previously unfavorable hydrocarbons contracts. The Ghana economy is now “showing signs of stabilization” due to an IMF-supported economic program.
But LNG imports will help the nation secure its own energy security as it plans on doubling its domestic electricity demand from 2022 to 2030.
Currently, all of Ghana’s natural gas imports come from Nigeria—Africa’s largest holder of proven gas reserves—via the West African Gas Pipeline (WAGP), but those imports have been unsurprisingly unreliable, both because Nigeria has in the past been an unreliable supplier and because Ghana has had trouble in the past meeting its repayment obligations.
Ghana’s energy source mix as of 2022 is 33.6% oil, 28.2% natural gas, 32.4% biomass, and 5.7% hydro. But as recently as in October, a natural gas shortage in the country triggered a complete power outage, highlighting its electrical deficit. Although Ghana routinely experiences blackouts, this was the most egregious one in years.
By Julianne Geiger for Oilprice.com
NOT BIDEN'S FAULT
Oil Majors Oppose Venture Global’s Plans to Delay Its Calcasieu Pass LNG Plant
The three supermajors that are suing Venture Global for breach of LNG delivery contracts have attacked again, asking U.S. regulators to be allowed to voice their position on Venture Global's plans to further delay the official launch of its Calcasieu Pass LNG plant.
Venture Global has been allowed to delay the commissioning of the Calcasieu Pass facility for one year by the Federal Energy Regulatory Commission but that permit expires soon. Venture Global wants to renew it for another year. The Big Oil companies appear to be of a different opinion and they want to voice their concerns.
Shell told Reuters that Venture Global’s conduct was very concerning and that it "intends to file comments or a protest in response."
BP, Shell, and Repsol all have long-term delivery contracts with Venture Global. However, the U.S. company has claimed its only existing LNG facility is not yet fully operational. This has, according to Reuters, allowed Venture Global to sell cargoes on the spot market instead of delivering them to BP, Shell, and Repsol. It has made billions from this strategy.
This prompted the three to file arbitration suits against Venture Global in response to Venture Global’s decision to withhold contracted cargos.
The three supermajors, along with two other European energy companies, were foundation buyers for the Calcasieu Pass facility, meaning they provided Venture Global with the money to build the place in Louisiana in exchange for a commitment from the company to supply them with certain volumes of LNG over a long-term period.
The facility has a capacity of 10 million tons, and it started producing in early 2022—right on time for Europe, which was beginning to experience a shortage. But instead of honoring its contracts with the European buyers, Venture Global chose to sell more LNG on the spot market.
By Irina Slav for Oilprice.com
Suncor Tops Profit Estimate as Oil Sands Production Soars to Record High
Canada’s Suncor Energy beat Q4 quarterly earnings estimates as its oil sands production jumped to an all-time high and total upstream production was the second highest in company history.
Suncor Energy (NYSE: SU) reported late on Wednesday adjusted operating earnings of US$1.21 billion (C$1.635 billion) for the fourth quarter of 2023, down year-on-year due to lower crude and products realizations. But the adjusted operating earnings of US$0.94 (C$1.26) per common share were above the US$0.78 (C$1.05) expected in the average analyst estimate, per LSEG data cited by Reuters.
The higher upstream production and strong downstream operations in the fourth quarter helped Suncor beat analyst estimates, despite the lower profits that all oil companies have reported this earnings season, due to weaker oil and natural gas prices.
Suncor booked for Q4 its “best-ever” Oil Sands production of 757,400 barrels per day (bpd), with upgrader utilization over 100% outside the maintenance period. Total upstream production hit 808,100 barrels of oil equivalent (boe/d) - the second-highest quarter in company history.
For full-year 2023, total upstream production of 745,700 boe/d was also the second highest in the company's history, while oil sands output was at a record high of 689,600 bpd, including best-ever production at Syncrude and Firebag, Suncor said.
“Upstream reliability across our operations was at or near record highs, achieving the second highest quarterly total production in the company's history and the highest quarterly Oil Sands production,” Suncor’s president and CEO Rich Kruger said.
“Downstream performance was equally strong with refining utilization in the quarter at 98%,” Kruger added.
Canadian oil producers in Alberta plan higher output for this year and expect to earn more from their heavy crude once the long-delayed expanded Trans Mountain Pipeline enters into service. Despite the uncertainty around the start date of the Trans Mountain Pipeline Expansion (TMX), some of the biggest Canadian producers plan to boost production in Alberta’s oil sands in the short to medium term.
The Premier of Alberta Danielle Smith has warned that lower oil prices will have an impact on the province’s new budget, forcing some spending cuts.
During a televised address on Wednesday night, Smith said "Lower resource revenues will certainly require us to show more restraint than previously predicted.”
"We will ensure this is done thoughtfully and with priority given to the programs and services Albertans most rely on such as health, education and social supports," the Premier added, as cited by the Canadian Press.
Alberta’s budget is tied to its oil revenues, which are calculated on the basis of the West Texas Intermediate benchmark. Even minor changes in the benchmark’s value can have an impact of hundreds of millions of dollars on the Canadian oil province’s finances.
Alberta’s FY 2023/24 budget was tied to an average WTI price of $79 per barrelbut for much of the year that ends this March, the U.S. benchmark has traded lower than this, meaning the budget calculations of the Alberta government had to be adjusted.
Recently, oil prices have been on the mend amid continued tensions in the Middle East but there is no guarantee the rally will either strengthen or continue seeing as there are bearish factors at play as well. Chief among these are doubts about the strength of Chinese oil demand.
Premier Smith has acknowledged that basing the province’s budget on oil revenues is not the wisest option, saying in her speech this week it was time for Alberta to get off the “budget rollercoaster” of oil revenues. She added, however, that the provincial government will not raise taxes to balance the new budget.
For the next financial year, the Alberta budget stipulates an average WTI price of $76 per barrel on average, declining to $73.50 per barrel in the following fiscal year.
Land Availability Forced India To Scale Back Solar Power Installations
India's solar installations fell dramatically last year as the country ran into difficulties acquiring the large swaths of land needed, a new research report said on Thursday.
Research firm Mercom Capital said in a new report that India's solar installations came in at just 13.4 GW last year, a 7.5 GW drop from the year prior.
The challenges that India faced in adding solar installations were not the high cost of solar. The biggest challenges were delays in land acquisition, connectivity issues, and new regulations such as General Network Access (GNA) and grid compliance.
"Module price drops in Q3 led to increased orders, but grid compliance and last-minute connectivity issues due to new regulations caused project commissioning delays," added Priya Sanjay, Managing Director of Mercom India.
The research report elaborated that the grid connectivity challenges, power evacuation concerns in areas inhabited by a bird known as the Great Indian Bustard, and project extensions all contributed to the decline in installations last year, along with compliance with the amended grid code provisions.
As of the end of last year, India's total solar capacity stood at 72GW—85.4% of which is utility-scale projects and 14.6% of which is rooftop solar.
India's large-scale solar project pipeline is 105.3 GW, with an additional 70.6 GW of projects tendered and awaiting auction as of the end of last year.
"Compared to most of 2023, market challenges like ALMM and high module prices no longer hinder projects. The absence of these financial obstacles allows previously stalled projects from 2023 to potentially proceed toward commissioning now," Sanjay said. He also called on the government to "ensure adequate substations and transmission infrastructure to accommodate the large capacity of projects" commissioning in Q1 2024.
India’s Refining Margins Slump as It Struggles to Secure Russian Oil
Refining margins for India’s biggest state-owned refiners have dropped in recent months amid more difficult access to Russian crude and soaring freight rates due to the Red Sea disruption to crude shipments, analysts and traders tell Bloomberg.
For most of 2023, Indian refiners enjoyed high refining margins and profits as they imported cheap Russian crude at $20 a barrel and more below international benchmarks.
Margins started eroding last quarter, although they are still higher than before the Russian invasion of Ukraine, which upended global crude trade flows. The decline in refining margins is due to higher costs for Indian refiners because of higher competition for Russian supply in Asia, increased freight costs, and tougher U.S. sanctions enforcement, which has limited India’s access to very low-priced crudes from Russia.
India could lose its refining advantage if it loses its edge on procuring cheaper crude from Russia, Mukesh Sahdev, head of oil trading and downstream research at Rystad Energy, told Bloomberg.
Stricter sanctions enforcement, narrowing discounts of Russian grades, and spiking freight rates due to the threats to shipping in the Red Sea have weighed on India’s crude purchases and imports of Russia’s oil in recent weeks.
The tougher enforcement of the G7 sanctions and related payment issues have been holding up Indian purchases of some cargoes of Russian crude oil, with tankers previously headed to India turning back eastwards, tanker-tracking data monitored by Bloomberg showed early this year.
Supply of Russia’s Sokol grade to India seems to be particularly hit by the tougher sanction enforcement.
In January, India’s crude imports from Russia slipped for a second consecutive month and were at their lowest level in a year, according to tanker-tracking data reported by Reuters.
Russia continues to be India’s top crude supplier, but deliveries to India fell by 4.2% from December to 1.3 million barrels per day (bpd) in January, per data from LSEG cited by Reuters. Vortexa pegs India’s crude imports from Russia at 1.2 million bpd last month, down by 9% month-on-month.
By Tsvetana Paraskova for Oilprice.com
Loophole Allowed Russia to Earn $1.2 Billion From Fuel Sales to the EU
An EU sanctions loophole that allows imports of Russian crude if it’s refined elsewhere made Russia an estimated $1.2 billion (1.1 billion euros) from sales of fuels in the European Union last year, despite the embargo on direct imports from Russia, an investigation by NGO Global Witness showed on Friday.
For more than a year, the EU has had a ban in place on imports of seaborne crude oil and fuels from Russia – with a temporary derogation for Bulgaria – as the bloc and its U.S., UK, and other allies look to stifle oil sales revenues for Vladimir Putin to wage his war in Ukraine.
However, Russian crude oil refined into fuels elsewhere, in India, for example, can be imported into the EU and the Kremlin is still receiving revenues for its fuels ‘laundered’ outside Russia.
Global Witness has tracked seaborne flows of crude from Russia to refineries around the world and then on to the European ports, and revealed that in 2023, an estimated 35 million barrels of Russian oil entered the EU in the form of refined petroleum products. It’s impossible to track specific molecules, but Global Witness analyzed the relative volume of Russian versus non-Russian oil used in a refinery’s feedstock, where data is available.
“The fuel is entering through a not-so-small loophole left in EU sanctions which allows products refined from Russian oil to flow into the bloc. This has resulted in a ‘laundromat’ where refineries in countries like India and Turkey, can import discounted Russian crude, refine it into products like diesel, jet fuel, or gasoline, and legally sell the refined oil to embargoing jurisdictions like the EU,” Global Witness said.
Through the same loophole, Russian fuel is also making its way into the UK and the U.S. In August 2023, a Global Witness analysis showed that one in every 20 UK flights ran on jet fuel made from Russian oil, and in November Global Witness reported that the U.S. had imported 30 million barrels of fuel from refineries that import Russian oil.
