TotalEnergies affirms drive for LNG as bunker fuel, eyes biomethane

Highlights

IMO GHG emissions cuts targets in focus

Global LNG bunker market could reach 10 million mt a year by 2025

Biomethane, along with LNG, offers viable decarbonization pathway

TotalEnergies remains upbeat on the uptake of LNG as a bunker fuel as stricter international rules loom in global shipping, viewing the fuel as a financially stable route to biomethane use.

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This scenario would work well for the company, which is a significant gas producer. Its production averaged 2.87 million boe/day average in 2020 and around 55% of that was gas, the company said on its website.

TotalEnergies started planning planning to deliver cleaner marine fuel solutions several years ago through a range of investments in LNG infrastructure at key bunkering hubs and other initiatives, it said in a recent report, with the company taking delivery of is first chartered LNG bunker vessel–Gas Agility–in August 2020 following the signing of a time charter party agreement with Mitsui O.S.K. Lines, Ltd. in February 2018. It is also currently the world’s largest supplier of LNG as a bunker fuel.

In 2021, Total Marine Fuels, a part of TotalEnergies, was awarded a LNG bunker supplier licence by the Maritime and Port Authority of Singapore, for a five-year term starting January 1, 2022 in the city-port.

FueLNG and Pavilion Energy Singapore already exist as licensees in Singapore, the world’s largest bunkering port, which recorded sales of 50,000 mt of LNG bunkers in 2021 and saw its first ship-to-ship LNG bunkering operation completed in March.

Today, there are 26 LNG bunker vessels in operation globally and the fleet will grow to 43 units offering an aggregated capacity of between 7 and 8 million tonnes per year by early 2024, TotalEnergies said.

TotalEnergies forecasts the LNG bunker market could reach 10 million mt a year by 2025 and represent 10% of the bunkering market by 2030.

LNG provides immediate benefits

In April 2018, the IMO laid out its strategy for the shipping industry to reduce its total GHG emissions by at least 50% from 2008 levels in 2050.

SEA-LNG, a multi-sector industry coalition established to demonstrate LNG’S benefits as a viable marine fuel, last year said that an independent study reconfirmed that greenhouse gas reductions of up to 23% were achievable from using LNG as a marine fuel, depending on the marine technology employed.

LNG also comes with numerous other advantages– it is a proven and mature technology, is readily available, has a rapidly growing bunkering network.

Although LNG has been criticized for its contribution to methane slips, engines are being developed to address this issue. LNG’s viability is proven on a well-to-wake basis, and depending on the technology employed, is capable of reducing GHG emissions by about 23% compared with standard conventional fuels, an independent study commissioned by industry coalitions, SEA-LNG and SGMF, stated.

Hapag Lloyd and CMA CGM are among global shipping companies championing the use of LNG as a marine fuel by putting in orders for LNG-powered ships

In Asia, AET, a subsidiary of MISC Berhad, remains committed to using LNG as a marine fuel, while Japan’s Mitsui O.S.K. Lines also plans to launch 90 LNG-fueled ships by 2030.

Shippers, however, currently have to pay high prices for the fuel.

S&P Global Platts assessed LNG as a bunker fuel at Rotterdam at $26.26/gigajoule/cu m Jan. 18, compared with $20.35/gj/cu m for methanol as a bunker fuel at the port and $15.88/gj/cu m for delivered 0.5% sulfur fuel oil, the currently prevalent bunker fuel.

The next step

“As a next step in its evolution, we believe that biomethane, together with LNG, can provide a viable pathway to achieve shipping’s decarbonization goal. The biomethane market is growing and has huge opportunities to become a global industry,” TotalEnergies said.

In 2020, biomethane production reached about 50TWh globally via supply from 1,100 operating plants and this has the potential to grow to reach a capacity of 8,500 TWh, the company said.

Estimated sustainable global supplies could potentially exceed the future energy demand of the global shipping fleet and bioLNG will likely be commercially competitive relative to other low- and zero-carbon fuels.

S&P Global Platts Analytics expects around 60% of total bunker demand to be replaced by alternative fuels to achieve IMO’s 2050 emission reduction targets.

Expanding LNG-fueled fleet could enable a pivot to bioLNG without needing to undertake any modifications, meaning the existing supply infrastructure would be fit for bunkering purposes with either fuel when bioLNG becomes scaled up, TotalEnergies said.

“This benefit alone will help reduce the capital outlay for brand new alternative fuels infrastructure, which it is estimated, could run into trillions of dollars,” the company said.

The company believes biofuels is an option for today. It plans to increase biofuels production capacity from 0.3mt/year in 2020 to 2mt/year by 2025 and 5mt/year by 2030.

To effect that, TotalEnergies is seeking to develop existing assets, such as its La Mede biorefinery, which was converted from a conventional refinery in 2019 and has the capacity to produce 500 KT of biofuels annually.

A long-term alternative is hydrogen. In July 2020, TotalEnergies set up a Clean Hydrogen business unit, with the goal of shaping the company’s ambition to become a large-scale producer of carbon-free hydrogen.

Japan's Suiso Frontier in Australia to load first liquefied hydrogen cargo

Highlights

Sails back after three-four days at Victoria

Started 9,000 km journey from Kobe Dec. 24

Significant development for hydrogen transport

Japan’s cargo ship Suiso Frontier is set to arrive at Australian state Victoria Jan. 20 and is expected to sail back with the world’s first liquified hydrogen in the week starting Jan. 23, a spokesperson of the hydrogen project Hydrogen Energy Supply Chain Project said, in what would be a significant development for transporting hydrogen for commercial use.

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A source close to the HESC project also said that the Suiso Frontier is arriving at Hastings Jan. 20. The Suiso Frontier, which had been estimated to arrive Hastings Jan. 19, was moored in South Australia and Victoria at 0627 GMT Jan. 20, according to Platts cFlow trade-flow analytics software.

Platts Cflow

Suiso Frontier left the liquefied hydrogen loading terminal Hy touch Kobe on Dec. 24 destined for port of Hastings in Victoria. After various field tests, it will return to Kobe loaded with liquefied hydrogen generated from brown coal in the middle of February 2022, according to a statement from Hydrogen Energy Supply-chain Technology Research Association, or HySTRA, in December.

HySTRA, whose members are Electric Power Development or J-POWER, Shell Japan, Iwatani, Kawasaki Heavy Industries, or KHI, Marubeni, ENEOS and Kawasaki Kisen Kaisha, is the Japan-funded portion of the HESC pilot phase.

The Australia-funded portion of the HESC project is coordinated by Hydrogen Engineering Australia, or HEA, a consortium comprised of KHI, J-POWER, Iwatani, Marubeni, AGL and Sumitomo, with HEA being a 100% subsidiary of KHI. The Australian and Victorian Governments are providing funds to the Australian portion.

The HESC project aims to produce and transport clean liquid hydrogen from Australia’s Latrobe Valley and the key objective of the pilot project is to demonstrate an end-to-end supply chain with Japan, that would cover a one-way distance of 9,000 km. It involves brown coal gasification and hydrogen refining in the Latrobe Valley and hydrogen liquefaction and storage of liquefied hydrogen at the port of Hastings.

The 8,000 gross tonnes Suiso Frontier, the world’s first liquefied hydrogen carrier with a cargo loading capacity of 1,250 cu m, is using one of the two storage tanks for carrying some 75 mt of liquefied hydrogen for this transport, a source told S&P Global Platts in December.

Suiso Frontier has been built by KHI.

Platts assessed Victoria hydrogen produced via lignite gasification, with CCS, including CAPEX at $2.58/kg Jan. 19, up 3.2% from Dec. 20.

Japan hydrogen produced via SMR without CCS, including capex was assessed at $4.12/kg Jan. 19, down 42.7% from Dec. 20.

INTERVIEW: Engie eyeing Saudi Arabia, Oman green hydrogen projects amid $5 bil UAE deal

Highlights

Design changes would lower emissions

Three trains already operating

Sempra proposed design changes to the expansion of its Cameron LNG export terminal that would lower the overall production capacity and postpone the timeline for commercially sanctioning the project to 2023.

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Cameron LNG, the subsidiary that owns and operates the Louisiana LNG export facility capable of producing roughly 12 million mt/year of LNG, asked the Federal Energy Regulatory Commission in a Jan. 18 filing to approve the amended plans. The amendment would let the company pursue a 6.75 million mt/year, single gas liquefaction train expansion (CP22-41), in place of an existing authorization for a two-train expansion that would have added a total 9.97 million mt/year of production capacity. FERC approved a permit for the two-train project in 2016.

The subsidiary estimated, in a project schedule included in the filing, that FERC could approve its permit amendment by January 2023 to facilitate the start of construction by April of that year. The developer said commercial service could begin in the third quarter of 2027, nearly three years later than the currently permitted time for completing the project.

The developer told FERC that the proposed design changes would lower greenhouse gas emissions associated with the project and boost the reliability of the additional liquefaction train. Three trains are already operating at the Cameron LNG terminal.

Beyond producing less LNG, the developer said planet-warming emissions would be lower than they would have been if the original expansion project was built because the new design calls for electric drives for the additional LNG facilities. Previous plans had called for on-site gas turbine drives.

The new project also called for including tie-in facilities to enable the capture of CO2 from Train 4 and sequestration at facilities in the Gulf Coast “if and when such infrastructure is developed and assuming it is accessible to Cameron LNG both logistically and economically.”

Plans to cancel the already authorized Train 5 would also entail eliminating a proposed fifth LNG storage tank, but the developer said there would be no change to existing marine facilities.

A spokesperson for Cameron LNG did not immediately respond to questions on Jan. 19.

Cameron LNG is a joint venture of Sempra Energy subsidiary Sempra LNG, TotalEnergies, Japan’s Mitsui, and a company jointly owned by Mitsubishi and Nippon Yusen Kabushiki Kaisha. Sempra indirectly holds 50.2% of the Cameron LNG export project.

In 2021 there was a flurry of commercial activity tied to current and proposed US LNG export terminals amid strong global demand for natural gas. The main beneficiaries of the deal-making, especially with Chinese buyers, were Cheniere Energy and Venture Global LNG, as high spot prices in end-user markets spurred new term deals that carry a lower fixed price. At least two proposed US projects were also scrapped in 2021 — Pembina Pipeline’s Jordan Cove in Oregon and Exelon-backed Annova LNG in Texas.

More than a dozen North American LNG developers are competing to advance their projects in the face of challenges that include pressure from buyers to be flexible on pricing and contract terms, as well as to bring down project costs. Developers have also faced growing concerns over greenhouse gas emissions associated with US LNG throughout the natural gas supply chain.

Besides Cameron LNG, Sempra is constructing its $2 billion Energía Costa Azul terminal on the West Coast of Mexico, which could start producing LNG in 2024 with a production capacity of 2.5 million mt/y before a potential expansion. The company is also developing the 11 million mt/year Port Arthur LNG export project in Texas and another midscale LNG export terminal in Mexico.

Sempra has ranked building the Energía Costa Azul facility on time and on budget as the top priority among its LNG projects. But executives said during their most recent earnings call in November 2021 that the company would then turn to a projected 7 million mt/year expansion of the Cameron LNG terminal. Sempra said it had all of the preliminary agreements in place for the final deals that will underpin the project.

“Our likelihood of going forward there we account as being relatively high,” Sempra Energy CEO, President and Chairman Jeff Martin said at the time.

Colder weather, LNG import push reset outlook for New England winter gas prices

Brazil's Petrobras to spend record $460 million on refinery work in 2022

Highlights

Follows record $420 million in 2021

Refinery utilization at 83% of capacity

Looking to boost ULSD production

Brazilian state-led oil company Petrobras plans to boost spending on refinery maintenance to record levels in 2022 amid ongoing refinery sales and ULSD expansion projects, the company said Jan. 19.

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Petrobras expects to spend $460 million in 2022, topping the previous record of $420 million set in 2021. Despite the shutdowns, Petrobras said that refinery utilization reached the highest in five years at 83% of capacity in 2021.

The spending comes amid a restructuring in Petrobras’ refining portfolio after a 2019 antitrust agreement ended the company’s monopoly in Brazil’s refining segment. Petrobras agreed to sell eight of the company’s 13 operated refineries in a deal with regulators.

Petrobras has so far sold one refinery and signed sales agreements to sell two additional units. Two refinery sales remain pending, while Petrobras expects to restart the sales process for three additional refineries in the second half of 2022, likely after October’s presidential elections.

The shutdowns in 2021 led to inspections and maintenance work on more than 4,000 pieces of equipment, Petrobras said.

“Petrobras plans an even bigger challenge for the year 2022, in which spending is estimated on the order of $460 million on maintenance shutdowns of units at its refineries, which will involve around 4,500 pieces of equipment,” the company said.

The maintenance spending is part of a broader plan to invest $6.1 billion in Petrobras’ refining system over the next five years. That includes three major projects in the 2022-2026 strategic plan aimed at increased production capacity, “especially of high-quality refined products such as ULSD,” Petrobras said.

The plan, released in November, included the surprise announcement that Petrobras would complete the second refining train at the Refinaria do Nordeste, or RNEST, plant in Pernambuco state. The project will add about 95,000 b/d in ULSD output, Petrobras said.

The $1.2 billion project will bring the refinery, which is also known as Abreu e Lima, up to its initially planned full capacity of 260,000 b/d by 2027, according to Petrobras. RNEST is currently limited to processing about 100,000 b/d by regulators because the unit’s full suite of air-emissions equipment was never installed.

Petrobras also plans to integrate the Refinaria Duque de Caxias, or REDUC, in Rio de Janeiro state with the nearby GasLub Itaborai lubricants facility. That project will add 93,000 b/d of ULSD and jet fuel output as well as 12,000 b/d of high-quality lubricants production, according to Petrobras.

A new hydrotreatment facility will also be installed at the Refinaria de Paulinia, or REPLAN, in Sao Paulo state, while Petrobras plans adjustments at REDUC and the Refinery Henrique Lage, or REVAP, in Sao Paulo. The three projects combined were expected to add 132,000 b/d of ULSD output, according to the company.

“The projects to be implemented will position the company among the best refiners in the world in terms of efficiency and operational results, with a focus on high-value products and lower carbon emissions,” Petrobras said.

3R Petroleum talks

In a separate statement, Petrobras said that it expected to complete negotiations to sell a cluster of oil fields in Rio Grande do Norte state to upstart 3R Petroleum in January. Petrobras and 3R Petroleum entered exclusive talks about the Polo Potiguar group of 22 onshore and shallow-water offshore concessions in August 2021.

3R Petroleum, which has made several deals with Petrobras since 2019, made the best proposal at a value of more than $1 billion, according to Petrobras.

In addition to the production fields, the deal also includes a small processing facility known as the Refinaria Clara Camarao, or RPCC, and three natural gas processing plants.

Saudi energy minister hones plea to target carbon emission; not oil and gas

Highlights

Future oil and gas should be decarbonized, not sidelined

Key producers looking to keep oil, gas on table in climate talks

Countries are asking for domestic net-zero roadmaps: IEA’s Birol

Saudi Arabia’s energy minister has renewed a plea for the world to take an energy-agnostic approach to curb climate-harming greenhouse gases rather than shunning oil and gas, calling on those calling for an end to fossil fuels to show their “true colors”.

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Global leaders should leave room for carbon-abated oil and gas production under future energy scenarios by using technology such as carbon capture and storage, Saudi energy minister Prince Abdulaziz bin Salman said while speaking to the World Economic Forum on an energy transition panel.

“We are all trying to congregate around the idea of reducing emissions of all greenhouse gases,” bin Salman told the panel. “We have to be honest about; are we really trying to achieve that goal or are we trying to take that hope as a pretext to … get rid of hydrocarbons … I really would like to see the true colors of everybody,” he added.

Reiterating previous comments around the need for future global oil and gas supplies to be decarbonized rather than sidelined, bin Salman said countries should “choose their own fitting choice based on their natural national resources and national abilities.”

Saudi Arabia, the world’s biggest oil exporter, is seeking to reduce its emissions while at the same time boosting its oil production capacity to cater to an expected rise in global crude demand over the coming decade.

Last year it unveiled plans to reach net-zero emissions by 2060 but the targets only apply to the country’s domestic emissions and do not cover greenhouse gases released from the use of its oil outside its territory.

In December, the Saudi energy minister highlighted the risk of an “energy crisis” this decade if there is not enough spending to sustain necessary oil and gas supplies.

His comments also come a day after the UAE, OPEC’s third-biggest producer, said climate talks during COP28 — to be held in the UAE in 2023 — should include input from oil and gas experts because the world can not unplug suddenly from the current energy system.

Domestic roadmaps

Bin Salman has been vocal in his criticism of the International Energy Agency’s landmark net-zero energy roadmap outlined in May 2021, calling it a “La La Land scenario” given the impact on the future demand for oil.

The report sparked controversy after calling for no new upstream oil and gas projects to be developed in order to meet climate goals by 2050. In order to slash carbon emissions to net-zero over the next three decades, global oil supplies would need to shrink more than 8% annually, down to 24 million b/d in 2050, from pre-pandemic levels of just above 100 million b/d, the IEA report concluded.

Also speaking on the World Economic Forum panel, the IEA’s head Fatih Birol defended the net-zero roadmap, saying the transition away from oil, gas, and coal needs to be achieved in addition to carbon abatement technologies in order to meet Paris climate targets on global warming.

“We did not say it is easy … to go from 80% of the energy coming from fossil fuels today to net-zero emissions by 2050 requires a Herculean effort … very, very difficult but it’s not impossible,” Birol said.

“Without fixing the problem in the energy sector, we have no chance whatsoever to fix our [climate] problems.”

Birol said, since releasing the scenario last year, many governments including India, Chile, Indonesia, South Africa, and in Europe have asked the energy watchdog to develop net-zero reports tailored for their specific domestic energy needs, adding “we are working for the various countries to prepare their domestic roadmaps.”

ANALYSIS: European diesel tightness widens backwardation to 3-year highs in January

Highlights

ICE LSGO prompt spread around 3-year highs

Diesel supply to tighten as imports dwindle

European diesel market structure has rallied to a strong backwardation in January, widening further from December, as changing middle distillate yields and trade flows limit diesel supply.

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Backwardation widens rapidly

Intermonth spreads in the ICE low sulfur gasoil futures — the key European futures benchmark for middle distillate markets, and indicator of market strength — have jumped since the beginning of 2022.

The outright value for the front month contract has also rallied to seven-year highs.

The prompt spread — February/March — was assessed at a three-year high at $13/mt backwardation Jan. 17, the highest since November 2018, having increased at a rapid pace from just 75 cents/mt on Dec. 31, 2021.

The balance-month to front month backwardation in CIF NWE ULSD cargo swaps reflected a daily backwardation of 39 cents/mt Jan. 18.

Despite the prompt structure of ICE low-sulfur gasoil futures weakening slightly on Jan. 18 with the February/March ICE LSGO backwardation reducing by 75 cents/mt to $12.25/mt and the March/April backwardation also narrowing by 75 cents/mt to $11.75/mt, traders remained bullish.

“[The strong backwardation] does reflect what is happening in the market; whether the exact value is correct is a tricky one,” a trader told S&P Global Platts Jan. 19. “On the supply side, it makes sense that the prompt is a bit pricey, due to lower production of diesel as a result of gas prices, and now high incentive to produce jet, while there are lower volumes arriving, and even small volumes departing Europe,” the trader said.

The trader added that the market did not expect this backwardation a month earlier.

Despite the weakening structure on Jan. 18, the outright value for the front month ICE LSGO contract continued to rise to a fresh seven-year high, assessed $3/mt higher on the day at $765.25/mt Jan. 18. This value is the highest since October 2014.

Tightening diesel supply

While demand for diesel across Europe remained reasonably steady, supply side fundamentals look set to tighten further in late January and moving into February. The import arbitrage flows are expected to dwindle and refiners were looking to adjust diesel production downwards, instead favoring the more profitable jet fuel.

The volume of ultra low sulfur diesel set to arrive in Europe from East of Suez markets in January totaled 859,300 mt as of Jan. 14, according to commodity firm Kpler data and shipping fixtures. This compared with just over 2 million mt that arrived in Europe in December.

Arrivals are expected to decrease further in early February, due to closing arbitrage economics, traders said.

In addition, imports arriving in Europe from the US Gulf Coast were minimal. The imports were expected at around 209,200 mt in January, according to Kpler data and shipping fixtures, with traders saying the arbitrage was closed.

Meanwhile, an open reverse arbitrage to send European diesel trans-Atlantic could reduce European supply further, with several tankers fixed on the route but total volumes set to move were unclear.

“At the moment we are seeing the market tight in Europe overall, cargoes headed trans-Atlantic and not much diesel production,” a second trader said.

Diesel production at European refineries has been hindered by poor cracking and desulfurization margins since the rally in natural gas and hydrogen prices from September. The two products are key components of the diesel production process.

However, the changing relationship between diesel and jet fuel crack spreads is set to lead to further diesel production cuts, as refiners are poised to swing output in favor of jet fuel.

This comes as physical cracks versus Brent hit two-year highs and jet fuel forward cracks settled above diesel cracks for the remainder of 2022, trading sources said.

The jet fuel physical FOB Rotterdam barge crack versus Dated Brent was assessed at $17.13/b Jan. 17, last assessed higher Nov. 6, 2019, before weakening to $16/b Jan. 18. The corresponding FOB ARA ULSD barge crack was assessed at $15.37/b Jan. 17, weakening to $15/b Jan. 18.

“There is less incentive to blend jet into the diesel pool, so it has totally changed the picture we were seeing the last few months… By the end of the month we will already see better jet supply, less diesel,” the first trader said.

Oil and gas should be part of UAE's COP28 talks as they're still needed: minister

Highlights

World can’t switch off suddenly from energy system: UAE’s al-Jaber

UAE, OPEC’s third biggest producer, will host COP28 in 2023

Discussions during COP28, to be held in the UAE in 2023, should include input from oil and gas experts because the world can’t unplug suddenly from the current energy system, the UAE’s minister of Industry and Advanced Technology said Jan. 18

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The UAE, OPEC’s third biggest producer, is hosting COP28 at a time when the country’s top energy producer Abu Dhabi National Oil Co. is seeking to boost its oil production capacity to 5 million b/d by 2030 from about 4 million b/d now. ADNOC says the world will need its oil because it is low-cost and low-carbon.

“We want to successfully transition to the energy system of tomorrow,” Sultan al-Jaber, who is also UAE’s special envoy for climate change and ADNOC CEO, told an Atlantic Council virtual event. “We can’t simply unplug from the energy system of today and we can’t do this with a flip of a switch. We need to include the energy experts in the consultations and in the discussions and we need to make economic systems work more efficiently with much less carbon.”

Officials in the UAE, the first country in the Middle East to make commitments toward zero carbon emissions by 2050, have argued that producing the least carbon intensive energy can go in parallel with lowering emissions and developing renewable energy and clean hydrogen.

The UAE’s 2050 pledge was followed by similar commitments from Saudi Arabia and Bahrain to reach zero emissions by 2060.

Disruptive transition

“Our goal by undertaking these activities and these initiatives is to hold back emissions, not to hold back progress or economic development,” said Jaber. “As long as the world continues to rely on oil and gas, we can play a very critical role in helping to ensure reliable supplies of the least carbon intensive oil and gas and we can make sure that this is available to the market where it is needed.”

Jaber’s comments are in line with statements from Saudi officials including Energy Minister Prince Abdulaziz bin Salman, who has said energy transition should not be disruptive to the world.

“Look at what is happening in the so-called transition that is happening elsewhere, it is disruptive,” the Saudi energy minister told the virtual Abu Dhabi Sustainability Week summit on Jan. 17.

“If it is disruptive to the economy, if it is disruptive to sustainability, if it is disruptive to the well-being of the citizens here and there and elsewhere, it should be reconsidered.”

Energy security should remain a top priority for the world, which should focus on cutting emissions and not excluding various energy sources, the prince added.

“Let’s not be picky and choosy about what solution or what energy source — if you want inclusiveness you have be comprehensive. What matters the most is reduction of emissions by all,” he said.

TotalEnergies, Inpex sell stakes in mature Angola oil assets to Somoil

Highlights

Deal includes offshore Kuito and Lianzi oil fields

Angola Block 14 B.V. produced 9,000 b/d in 2021

New projects could help Angola revive oil output

France’s TotalEnergies and Japan’s Inpex Corporation have signed a deal to offload their non-operated interests in Angola Block 14 and Block 14K to Angolan Company Somoil, both companies said Jan. 17.

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Somoil will acquire the company Angola Block 14 B.V., owned by TotalEnergies Holdings International B.V. (50.01%) and Inpex Angola Block 14 Ltd (49.99%).

Angola Block 14 B.V. had a non-operated interest in a handful of mature oil assets offshore Angola, namely the offshore Kuito and Lianzi oil fields.

Kuito was Angola’s first every deepwater oil field, but production stopped in late-2013. Block 14 also contains the Benguela Belize–Lobito Tomboco, Belize North, Benguela North, Tombua, Landana, Lucapa Field and the Malange Field.

This deal will see Somoil get access to these offshore blocks, which have been producing since 1999. Net production from Angola Block 14 B.V. was 9,000 b/d of oil equivalent in 2021, the statement added.

Angola’s crude production has been on a downward spiral in the past decade.

The country, which typically produces heavy but sweet crude, has traditionally been among the top suppliers to China. But key fields like Cabinda, Dalia, Nemba, Girassol, Hungo, Kissanje, Pazflor and Plutonio have all declined and matured at the same time.

“By divesting this interest in mature fields, TotalEnergies is implementing its strategy to high-grade its oil portfolio, focusing on assets with low costs and low emissions,” said Henri-Max Ndong-Nzue, Senior Vice President Africa of TotalEnergies Exploration & Production.

But Ndong-Nxe said despite this deal, the French company is focused on retaining its position as one of Angola’s leading oil operators.

The CLOV, Dalia, Girassol and Pazflor production hubs, operated by Total, all lie in Block 17, and the country is Total’s second-largest in terms of oil output, after the UAE.

Total’s equity share of Angolan upstream production averaged 212,000 boe/d in 2020. It operates blocks 17, 31, 16, 48, 20/11, 21/09, and has stakes in blocks 0, 14, 14K, and Angola LNG.

New startups

Angola used to be Africa’s second-largest oil producer until early 2021, but has its seen output tumble to 17-year lows. Crude output has averaged around 1.13 million b/d in 2021, down from a 2008 peak of 1.9 million b/d, according to S&P Global Platts estimates.

But there has been a slew of new startups, including five in the past eight months: TotalEnergies’ 40,000 b/d Zinia Phase 2 and 40,000 b/d CLOV Phase 2, BP’s 30,000 b/d Platina field, and Eni’s 15,000 b/d Cabaca North and 10,000 b/d Cuica projects.

The Angolan government has said these recent startups could help Angolan oil production reach 1.3 million b/d in the next three years.

The West African producer is now banking heavily on BP, Eni, TotalEnergies and ExxonMobil, all of which have recently resumed exploration and drilling work.

TotalEnergies is expected to drill the Ondjaba-1 wildcat exploration well in Block 48, and it is also finalizing the Chissonga field development in Block 16.

Record volume of certified gas hits US markets after strong commitments in 2021

Highlights

EQT, Seneca, Chesapeake, BPX Energy complete certification

Approximately 5 Bcf/d of Appalachia gas certified

Around 1.2 Bcf/d of Haynesville production certified

Record volumes of gas certified for its environmental credentials have come to the market after nearly two dozen US gas producers committed to external assessment of their emissions and ESG criteria last year.

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Over the last week, two US gas producers announced the completion of third-party certification processes, adding up to 5 Bcf/d of certified gas in Appalachia.

EQT, the largest US gas producer, announced on Jan. 14 that it had certified the majority of its natural gas production under both Equitable Origin’s EO100 Standard for Responsible Energy Development and the MiQ Standard on methane emissions. The producer received both certifications in November, with digital attribute certificates becoming available more recently, according to a Jan. 14 press release. EQT produces around 4 Bcf/d in Appalachia.

“These results not only enable us to unlock growing domestic and international markets that are valuing a differentiated commodity, they also serve as an important validation of the environmental attributes of Appalachian natural gas,” EQT CEO Toby Rice said in a Jan. 14 statement.

EQT has also partnered with Denver-based continuous monitoring firm Project Canary on a pilot program, installing Canary X sensors on two well pads in southwestern Pennsylvania.

Earlier in the week, National Fuel Gas Company announced that its production arm, Seneca Resources, had received certification from Equitable Origin for just over 1 Bcf/d of Appalachia gas production.

“As we look ahead, we expect that the certification of Seneca’s entire Appalachian natural gas base will differentiate our responsibly sourced, low methane-intensity production with end-users and commercial markets,” Seneca Resources President Justin Loweth said in a Jan. 11 statement.

Like EQT, Seneca Resources has also partnered with Project Canary for a pilot program, which will assess around 300 MMcf/d of Appalachia gas production.

The two statements come on the heels of two earlier announced certifications in December, which added 1.2 Bcf/d of certified gas in the Haynesville Shale.

On Dec. 21, Chesapeake Energy confirmed that it had completed Equitable Origin and MiQ certification for approximately 1 Bcf/d of Haynesville gas production. The producer has also partnered with the two organizations to certify its Appalachia gas production, which is expected to be completed by the end of the second quarter of 2022, as well as signed pilot project deals in both basins with Project Canary. Additionally, Haynesville producer Vine Energy, which was acquired by Chesapeake in November, sought out Project Canary certification for the entirety of its production in August.

On Dec. 8, BP’s US onshore production business, BPX Energy, announced that it had received an ‘A’ grade on the MiQ Standard for approximately 200 MMcf/d of South Haynesville gas production in Texas.

Trading

With the certified gas market in its infancy, no clear consensus has been found on how this new product will be traded or where.

Several platforms to facilitate the trading and tracking of certified gas certificates – either bundled with physical natural gas or unbundled—have emerged, including the MiQ Digital Registry and Xpansiv.

MiQ launched its global secure digital ledger, the MiQ Digital Registry, in December to hold and track certificates from issuance to retirement. With many producers choosing to seek out multiple certifications, the MiQ Digital Registry has offered joint MiQ-EO100 certificates, as well as MiQ certificates. In addition to EQT, at least two other US producers have simultaneously sought out certification from both MiQ and Equitable Origin.

Xpansiv, an exchange that specializes in environmental commodities like carbon offsets and RECs, partnered with S&P Global Platts to launch Methane Performance Certificates in early October, which can be issued and tracked with Xpansiv’s Digital Fuels Registry.

Platts MPCs represent gas produced with a methane intensity of 0.1% or lower and are unbundled from the natural gas production underpinning each certificate’s creation. As of Jan. 13, the price of an MPC was assessed at $0.049/MPC, or $7.903/mtCO2e.

Xpansiv has also partnered with Project Canary, agreeing in November to provide the exchange with methane-emissions data gathered from its continuous monitoring systems.

Grades

EQT, Chesapeake Energy, and BPX Energy all reported receiving an “A” grade on MiQ’s sliding scale of “A” to “F”. An “A” grade represents a methane intensity of 0.05% or less while an “F” is more in the ballpark of 2%.

To put an intensity of 0.05% in context, One Future, a consortium of energy companies committing to reducing methane emissions, had a gas production sector goal of 0.283% in 2020, according to its most recent methane emissions intensity report.

Indaba Renewable Fuels to build two US-based SAF plants

Highlights

Two facilities to produce 6,500 b/d each

Production expected to begin in 2024

Will use Haldor Topsoe technology to make green hydrogen

California-based Indaba Renewable Fuels plans to build a refinery each in California and Missouri to make sustainable aviation fuel using technology from Haldor Topsoe, according to a Jan. 14 statement from Haldor Topsoe.

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Each facility is expected to produce 6,500 b/d of SAF beginning in 2024, the statement said.

Haldor Topsoe will also provide hydrogen technology allowing the facilities to lower the carbon intensity of the SAF, replacing fossil fuels with renewable liquids like LPG and naphtha, creating green hydrogen.

“We are excited to provide Indaba with refining technology and catalysts as they initiate production of renewable fuels in the US,” Henrik Rasmussen, head of Haldor Topsoe’s American operations, said in the statement.

Using Haldor Topsoe technology, Indaba will be able to use a variety of feedstocks from plant-, animal-, and grease-based sources to create low carbon intensity SAF that will qualify for California’s Low Carbon Fuel Standard Credits (LCFS), the statement said.

Haldor Topsoe is a Danish company and key provider of carbon emission technology to decarbonize hard-to-abate sectors. Indaba Renewable Fuels LLC is a waste-to-renewable fuels company based in southern California that converts plant and animal oils, fats, and grease-based feedstock into SAF.

Lower East of Suez gasoil, ULSD exports in Jan leave Europe tight

Highlights

More LNG diverted to combat power shortages in 2022

Diversions could impact LNG export commitments

First phase of carbon tax to target coal-fired power plants

The Indonesian government is expected to divert more LNG cargoes from national oil company Pertamina for domestic use to combat energy shortages in 2022 and launch a carbon tax for its coal-fired power sector in April.

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The Southeast Asian country is struggling with coal and LNG shortages, having imposed a short-lived ban on coal exports in early 2022, even as millions of consumers in Java, Madura, Bali and other islands suffered from power outages.

While President Joko Widodo has ordered Pertamina and private LNG producers to prioritize domestic needs, the country continues to see declining gas production at mature fields and falling investment in its oil and gas upstream sector, which caused supply issues to customers like Singapore in 2021.

Indonesia is now expected to strike a balance between energy security concerns as the world’s fourth-largest country by population, its competitiveness as one of Asia’s largest fossil fuel exporters and growing climate change concerns.

Its capital Jakarta is one of the world’s fastest sinking cities due to rising sea levels, putting the country at the crossroads of global warming and fossil fuel exports, while the government has made pledges towards net zero emissions by 2060 at COP26 last year, which will make 2022 a year of reckoning for policymakers.

LNG exports

Indonesia’s upstream regulator SKK Migas has allocated 58 LNG cargoes for state-owned power utility PT PLN (Persero) to generate electricity this year. The cargoes will come from the flagship Tangguh and Bontang LNG plants.

SKK said this compares to an official allocation of 58 LNG cargoes to PLN in 2019 for power generation, 40 cargoes in 2020 and 54 cargoes in 2021. PLN did not absorb the full amount of LNG cargoes that were contractually allocated in previous years, amounting to 13 unused cargoes in 2020 and 11 cargoes in 2021.

Growing energy shortages have increased the likelihood of more cargoes being diverted for domestic use in 2022, which could impact export commitments and the need for Pertamina and overseas LNG buyers to enter LNG cargo swaps, officials said.

“Currently, all related parties are ensuring the availability of energy for electricity, especially in the first quarter of 2022,” Deputy for Finance and Monetization of SKK Migas Arief Setiawan Handoko said in a statement in early January.

Energy and Mines Minister Arifin Tasrif confirmed at a press conference in January that the ministry had secured LNG supply, which was previously allocated for exports but would now be diverted to the domestic market. He did not provide further details. Pertamina and SKK Migas declined to comment.

SKK Migas’ Handoko said that the country’s plan to use more LNG for electricity generation is expected to improve “to ensure stable supply for buyers and sustainable production for sellers.”

Indonesia’s upstream oil and gas sector began supplying LNG for domestic use in 2012 with just 14 cargoes for sectors including power, industries and city gas. This number rose to as much as 60.6 LNG cargoes in 2019, but fell to 44.9 LNG cargoes in 2020 due to the pandemic and a decline in economic activity and energy demand, according to the regulator.

In 2021, energy consumption rebounded with a total of 56 LNG cargoes for domestic use, of which 54 LNG cargoes were allocated for electricity generation, with the remaining used by industrial sectors. More than 95% percent of LNG supply for domestic use is now being consumed by the electricity sector.


Explore this topic: Commodities 2022

Carbon tax

At COP26, Indonesia laid out decarbonization strategies under “Visi Indonesia 2045” and the “Long-Term Strategy on Low Carbon and Climate Resilient Development 2050” in its Nationally Determined Contributions, or NDCs.

It set a target of reducing greenhouse gas emissions by 29% on its own and 41% with international support by 2030. In order to meet these goals it passed a Presidential Regulation on the Economic Value of Carbon that serves to put a price on carbon.

Jakarta is expected to implement carbon taxes in phases, with the first one on coal-fired power plants as early as April 2022, which will be further expanded to other fuels and industries after 2025.

The initial carbon tax will be limited to Rupiah 30,000/mt CO2 equivalent ($2.10) and the plan is to produce a more detailed roadmap for carbon pricing and the setting up of carbon exchanges.

The exact manner of implementation of the carbon tax across coal, gas and other resources sectors is yet to be determined, and the impact on domestic and global supply chains is also uncertain.

Pertamina has been called upon to be the pillar of the country’s decarbonization and the NOC has laid out its own Long Term Plan 2020-2024 to cut emissions. While there is significant scope to build a carbon market with early movers like Australia and Singapore, the future roadmap is still uncertain.

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