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Q&A: LNG, renewables key for Australian gas: Jemena

  • : Electricity, Natural gas
  • 24/06/05

Australian gas pipeline and power distribution firm Jemena has been at the forefront of the country's biogas sector through its Malabar facility in Sydney, while continuing to supply natural gas and eyeing hydrogen blending. Argus spoke to managing director David Gillespie on the sidelines of the Financial Review ESG Summit in Sydney about the company's future and how he views Canberra's future gas strategy. Edited highlights follow:

Your thoughts on the future gas strategy, which was released with quite a bit of fanfare. What's the substance behind it?

It's a piece of work that to me is very science backed. And ultimately the whole system needs to transition. It can't just be a view of one technology doing the heavy lifting. I think it's a strong acknowledgement of the role of gas that's going to be here, for not just firming of renewable energy in the future, but also those hard to abate industrial sectors.

Ultimately over the long run I think gas itself is a fuel that's going to have a decarbonisation journey of its own. So it really promotes a conversation around getting down the path of a whole of system reduction of the energy sector's carbon footprint.

Regarding biogas, are you seeing any kind of levers in the works to encourage production?

Definitely there are green shoots. We've had the Malabar facility certified from a green power perspective and that's a great step. We're having really good engagement with government around inclusion of any purchases of that biomethane in the national greenhouse gas reporting, so if you buy certified biomethane you'll get the benefit for that in terms of emissions intensity of your business. We hope that's achieved within the next 12 months.

Ultimately a strong market signal to drive investment will be a renewable gas target that will see us with very clear investment signals around the role that will play in terms of its future mix and scale, first and foremost for the industrial load that is hard to abate.

Do you have an idea about what that target might look like and what sort of percentage?

I don't. What I would say is if you take just the Sydney basin, two-thirds of the gas that's flowing through it is for industrial use, roughly 60 PJ/yr (1.6bn m³/yr) of gas. If you can decarbonise half of that through economically rational projects, proximate to the network, then you're on a pathway to making big inroads in the country's most populous state.

We're looking at projects that are more scaled than the [2.5mn m³/yr] Malabar facility, more in the 1-2PJ range. So if you can encourage renewable gas further with targets, I think you'll really start to see some momentum.

Where's the 200 TJ/d (5.34mn m³/d) Eastern Gas Pipeline (EGP) reversal project at?

The [12km] pipeline to connect the [2.4mn t/yr] Port Kembla LNG terminal to the EGP was completed in December and the terminal construction will be complete by the first quarter of 2025, ahead of commercial operations from winter 2026. So the reversal activities we are completing will be lined up to be delivered by 1Q 2026.

I don't think there's any new gas supply outside of LNG terminals that has a clear pathway to market in terms of approvals and timeframes. We're absolutely supportive of encouraging new supply but ultimately the most near-term solution is LNG terminals.

Port Kembla's injection capacity is just over 500 TJ/d, about 40pc of the Victorian load today. So you're still going to, I think, need more supply over the long run as well. But this is going to be the first realistic option in the market.


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24/07/24

Repsol 2Q profit doubles but cash flow turns negative

Repsol 2Q profit doubles but cash flow turns negative

Madrid, 24 July (Argus) — Spanish integrated Repsol's profit more than doubled on the year in the second quarter, as lower one-time losses and better results in the upstream and customer divisions more than offset a weaker refining performance. But its cash flow turned negative as it completed the buyout of its UK joint venture with China's state-controlled Sinopec, raised investments and experienced weaker refining margins. Net debt was sharply higher, largely reflecting share buy-backs. Repsol has said it will acquire and cancel a further 20mn of its own shares before the end of the year, which will probably further increase its debt. It completed a 40mn buy-back in the first half of the year. Repsol's profit climbed to €657mn ($714mn) in April-June from €308mn a year earlier, when earnings were hit by a large provision against an arbitration ruling that obliged it to acquire Sinopec's stake in their UK joint venture. Excluding this and other special items, such as a near threefold reduction in the negative inventory effect to €85mn, Repsol's adjusted profit increased by 4pc on the year to €859mn. Repsol confirmed the fall in refining margins and upstream production reported earlier in July . Liquids output increased by 3pc on the year to 214,000 b/d, and gas production fell by 4pc to 2.1bn ft³/d. Adjusted upstream profit increased by 4pc on the year to €427mn. The higher crude production and a 13pc rise in realised prices to $78.6/bl more than offset lower gas production and prices, which fell by 6pc to $3.1/'000 ft³ over the same period. Adjusted profit at Repsol's industrial division — which includes 1mn b/d of Spanish and Peruvian refining capacity, an olefins-focused petrochemicals division, and a gas and oil product trading business — was down by 16pc on the year at €288mn. Profit fell at the 117,000 b/d Pampilla refinery in Peru after a turnaround and weak refining margins, and there was lower income from gas trading. Spanish refining profit rose on a higher utilisation rate and gains in oil product trading. Repsol's customer-focused division reported adjusted profit of €158mn in April-June, 7pc higher on the year thanks to higher retail electricity margins, a jump in sales from an expanded customer base, higher margins in aviation fuels and higher sales volumes in lubricants. Repsol swung to a negative free cash flow, before shareholder remuneration and buy-backs, of €574mn in the second quarter, from a positive €392mn a year earlier. After shareholder remuneration, including the share buy-backs and dividends, Repsol had a negative cash position of €1.12bn compared with a positive €133mn a year earlier. Repsol's net debt more than doubled to €4.595bn at the end of June from €2.096bn on 31 December 2023, reflecting the share buy-backs and new leases of equipment. By Jonathan Gleave Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Equinor 2Q profit supported by higher European output


24/07/24
24/07/24

Equinor 2Q profit supported by higher European output

London, 24 July (Argus) — Norway's state-controlled Equinor posted a small rise in profit on the year in the April-June period, as a lift in its European production offset lower gas prices. Equinor reported a profit of $1.87bn in the second quarter, up by 2.2pc on the year but down by 30pc from the first three months of 2024. The company paid two Norwegian corporation tax instalments, totalling $6.98bn, in the second quarter, compared with one in the first quarter. Equinor paid $7.85bn in tax in April-June in total. Its average liquids price in the second quarter was $77.6/bl, up by 10pc from the second quarter of 2023. But average gas prices for Equinor's Norwegian and US production fell in the same period by 17pc and 6pc, respectively. The company noted "strong operational performance and lower impact from turnarounds" on the Norwegian offshore, including new output from the Breidablikk field . Equinor's entitlement production was 1.92mn b/d of oil equivalent (boe/d) in April-June, up by 3pc on the year. The company cited "high production" from Norway's Troll and Oseberg fields in the second quarter, as well as new output from the UK's Buzzard field. But US output slid, owing to offshore turnarounds and "planned curtailments onshore to capture higher value when demand is higher", the company said. It estimates oil and gas production across 2024 will be "stable" compared with last year, while its renewable power generation is expected to increase by around 70pc across the same timespan. Equinor's share of power generation rose by 14pc on the year to 1.1TWh in April-June. Of this, 655GWh was renewables — almost doubling on the year — driven by new onshore wind capacity in Brazil and Poland. "Construction is progressing" on the UK's 1.2GW Dogger Bank A offshore windfarm , Equinor said. It is aiming for full commercial operations in the first half of 2025 at Dogger Bank A — a joint venture with UK utility SSE. Equinor was granted three new licences in June to develop CO2 storage in Norway and Denmark. The Norwegian licences — Albondigas and Kinno — together have CO2 storage potential of 10mn t/yr. The Danish onshore licence, for which Equinor was awarded a 60pc stake, has potential capacity of 12mn t/yr. Equinor has a goal of 30mn-50mn t/yr of CO2 transport and storage capacity by 2035. The company's scope 1 and 2 greenhouse gas (GHG) emissions amounted to 5.6mn t/CO2 equivalent (CO2e) in the first half of the year, edging lower from 5.8mn t/CO2e in January-June 2023. It also incrementally cut its upstream CO2 intensity, from 6.7 kg/boe across 2023, to 6.3 kg/boe in the first half of this year. Equinor has kept its ordinary cash dividend steady , at $0.35/share, and will continue the extraordinary cash dividend of $0.35/share for the second quarter. It will launch a third $1.6bn tranche of its share buyback programme on 25 July. By Georgia Gratton Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Idemitsu to start black pellet output in December


24/07/23
24/07/23

Idemitsu to start black pellet output in December

Tokyo, 23 July (Argus) — Japanese energy firm Idemitsu is planning to start black pellet production of 120,000 t/yr in Vietnam in December this year. Idemitsu has already completed construction of the black pellet plant in Vietnam's Binh Dinh province in July 2023 and is now carrying out test operations. The black pellets produced at this plant will be transported to Japan for consumers that include power generation companies operating coal and biomass co-firing. The Vietnamese plant is managed by Idemitsu Green Energy Vietnam, which has become a 100pc subsidiary of Idemitsu in March this year. Idemitsu is planning to increase its black pellet output to 300,000 t/yr within three years after the start-up of the first plant. It final target is 3mn t/yr by 2030 , with an aim to launch projects in Malaysia and Indonesia in addition to Vietnam. The company is also considering empty fruit bunches as feedstock for biomass fuels. Idemitsu has been carrying out studies of coal and biomass co-firing and confirmed that it is possible to burn 35pc of black pellets with coal. The company has provided utilities with samples for test runs. Black pellets also can be used in other sectors, such as steel mills and cement plants. Black pellets, which have a higher calorific value compared with typical white pellet biomass, are produced by the torrefaction of acacia and other feedstock. The advanced fuel has better water resistance and grindability than white pellets and can be used in a similar way as coal. By Takeshi Maeda Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Gas discovery could extend Bolivia's export life


24/07/22
24/07/22

Gas discovery could extend Bolivia's export life

Sao Paulo, 22 July (Argus) — The estimated 1.7 Tcf of natural gas in Bolivia's Mayaya Centro-X1 field would expand the country's exporting capacity in 4-5 years but not much beyond that, according to market participants. The discovery — the largest find in Bolivia since 2005 and the first in the north of the country — was well-received in Bolivia and in neighboring countries. But some are skeptical about whether it actually holds 1.7 Tcf. "The government may be jumping to conclusions given the elements available so far," a hydrocarbons market consultant told Argus . Prior to the discovery, Bolivia was expected to cease exporting gas in 2030. By then, considering proved reserves, production will only be enough to supply domestic demand. Additionally, there are some logistics concerns, as the region around the Mayaya Centro-X1 field has no infrastructure for further exploration or pipeline transport systems. The mayor of the Bolivian capital La Paz, Iva Arias, said a hydrocarbons field would take 2-5 years to produce and start yielding royalties for the city. But if the reserves are indeed proven, the discovery would change Bolivia's natural gas reality, as its reserves dropped by around 70pc in the last decade. The expectations surrounding the find are added to the increasingly public animosity between President Luis Arce and former-president Evo Morales, his former boss. Both are claiming credit for the discovery and will use it to promote their 2025 presidential runs . Bolivia is still the largest exporters of natural gas to Brazil. State-controlled Petrobras and Bolivia's state-owned YPFB are partners in four Bolivian fields. Only four days prior to Mayaya Centro-X1 announcement, newly-appointed Petrobras chief executive Magda Chambriard visited Bolivia with Brazilan President Luiz Inacio Lula da Silva and announced plans to invest $40mn to drill an exploratory well in San Telmo Norte in 2025. Brazilian company Flxus also plans to invest in Bolivian gas . By Betina Moura Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Brazil issues guidelines for Amazon power program


24/07/22
24/07/22

Brazil issues guidelines for Amazon power program

Sao Paulo, 22 July (Argus) — Brazil's mines and energy ministry presented the initial guidelines for a program that aims to reduce power generation costs in the Amazon basin. The program also aims to reduce the carbon footprint of power generated in the Amazon basin. The government plans to hold public hearings to define the eligibility criteria for projects that can participate in the program. The program will use funds from the 2022 privatization of power company Eletrobras. The firm transferred R924mn ($166.7mn) to the federal government on 31 January. By law, these funds need to be used to reduce power generation costs and expand power transmission investments in the Amazon basin. Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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