India’s Petronet calls Dahej regas tariff “reasonable”

Spanish Market: Natural gas
25/10/24

India's state-run LNG terminal operator Petronet LNG has called its regasification tariff as "reasonable" at its 17.5mn t/yr Dahej terminal on the west coast after consumers' concerns that the firm was charging one of the highest rates in the world, it said in a press conference.

Petronet charges 62.91 rupees/mn Btu ($0.75/mn Btu) to regasify the fuel received at its Dahej terminal, the country's largest such facility, with plans to increase it by 5pc every year.

But the firm also expects an "upward revision" to the rates going ahead, it said in a separate analyst call on 24 October.

The tariff is part of the contractual obligation of capacity booking of customers, the management said, adding that the demand for natural gas in the country is not determined by regasification charges, but instead driven by international gas prices.

"Even if you tweak it by 5pc or 10pc, that is not going to change the consumer pattern of natural gas," chief executive officer Akshay Kumar Singh said in the press conference.

The higher tariff at Dahej terminal also compensates for lower capacity utilisation at Petronet's 5mn t/yr Kochi terminal, the board explained.

The Kochi terminal has kept its capacity utilisation below 25pc since its commissioning in 2013, but the board expects the situation to improve in the coming years as the 16mn m³/d Kochi-Bangalore pipeline comes online by March 2025.

Additionally, the country's gas regulatory board Petroleum and Natural Gas Regulatory Board (PNGRB) plans to lay a new pipeline south from Kochi, it announced in a separate statement issued on the same day. The bidding for the pipeline closes on 18 February 2025, the regulator added.

The new project will take years to be ready, Petronet CEO Akshay Kumar Singh said in the earnings call.

The southern 425-km long Kochi-Kanyakumari-Thoothukudi gas pipeline would be the crucial link between Petronet's Kochi and state-run refiner Indian Oil 5mn t/yr Ennore LNG import terminal, according to the pipeline regulator.

The proposed pipeline, which has an initial capacity of 6mn m³/d, will begin from the southern state of Kerala before entering the neighbouring state of Tamil Nadu, where Indian state-controlled refiner IOC's Ennore facility is located. The pipeline will enhance the availability of natural gas in the southern part of the country, further supporting the development of the city-gas distribution business in the region, the regulator added.

Most of the country's existing gas pipeline infrastructure is in the western and northern parts of the country.

Kochi LNG has a 1.44mn t/yr long-term agreement for LNG from Australia's Gorgon LNG project. It may sign more term contracts for the fuel once the pipes are laid.

Capacity expansion plans

Petronet remains committed to commissioning the expanded 5mn t/yr capacity addition at Dahej, Singh said, adding that this would take the entire capacity of the terminal to 22.5mn t/yr by March 2025.

Petronet commissioned two storage tanks, each with a capacity of 180,000 m³ at Dahej in September, taking the total to eight storage tanks. The company is also in the process of building a 2.5km jetty that can accommodate Q-Max LNG tankers as well as receive propane and ethane beside LNG, Singh added.

Petronet also plans to build a new 5mn t/yr import facility in Gopalpur on the east coast, with commissioning expected by 2027, Singh said. The company is in the final stages of acquiring land from the Odisha state government and has sought bids to build a jetty, Singh said. It had previously planned for a 4mn t/yr floating storage and regasification unit but had to abandon the idea after demand for the units rose following Europe's LNG terminal capacity additions to compensate for cuts in Russian gas supplies.

By Rituparna Ghosh

Related news posts

Argus illuminates the markets by putting a lens on the areas that matter most to you. The market news and commentary we publish reveals vital insights that enable you to make stronger, well-informed decisions. Explore a selection of news stories related to this one.

09/12/24

Shale M&A to pick up pace in 2025 after hitting pause

New York, 9 December (Argus) — A slowdown in shale deals in recent months is set to be reversed next year, helped in part by speculation that oil and gas mergers will have an easier time getting anti-trust approval under president-elect Donald Trump. The $12bn in upstream deals recorded in the third quarter was the lowest tally since the first three months of 2023, just before a record-breaking streak that reshaped the shale landscape and was dominated by blockbuster transactions involving ExxonMobil and Chevron. While buyers have been focused on winning approval from a zealous regulator and pushing deals over the finish line, attention is turning to the billions of dollars of unwanted assets they are likely to want to offload, with companies from ExxonMobil to Occidental Petroleum already active on this front. "You do one of these mega-mergers and now you have to pay for it," law firm Hogan Lovells partner Niki Roberts says. "You pay for it by selling off all the stuff you didn't really want to begin with." One potential upside from the Trump administration may be less attention from the Federal Trade Commission, which has paid closer scrutiny to oil deals in recent months as it cracks down on anti-competitive behaviour. Tie-ups have been delayed while the regulator has sought more details, and two high-profile oil executives were barred from the boards of their acquirers as a condition of approving deals. "The antitrust regulators have been viewed by particularly the traditional oil and gas industry of late as not being friendly to that industry," law firm Sidley global leader of energy, transport and infrastructure Cliff Vrielink says. "You're going to see less resistance to consolidation and you're going to see more people pursuing those opportunities." Oil market volatility has hampered mergers and acquisitions in the past, but observers say price swings are less of a factor these days. And more deals are needed to help companies boost their inventory of drilling locations for as long as cash flow remains king and growing through the drillbit is challenged. Lower interest rates, controlled inflation and regulatory reforms all point to a "robust" M&A market, Sidley partner Stephen Boone says. The majority of deal-making has been focused on oil in recent years, but natural gas is "having a bit of a moment", aided by the surge in demand from a boom in energy-hungry US data centres that are developing and supporting artificial intelligence, Boone says. Privates on parade Private equity is also making a gradual comeback, with teams looking to deploy fresh capital in oil and gas. Quantum Capital Group raised over $10bn in October and EnCap Investments has reloaded with about $6.4bn. "We are just now getting back to pre-pandemic levels of commitment," Boone says. "That bodes towards probably more private equity involvement in the oil and gas space." Fierce competition to get a foothold in the prized Permian basin of west Texas and southeastern New Mexico has sent valuations soaring, and prompted some would-be buyers to look further afield to plays such as the Uinta in Utah and North Dakota's Bakken. "The Permian stays of interest to many because of its consistent returns, but the Permian is a crowded place right now, and so I do think we'll see development of other basins," Roberts says. "But it's all going to depend on price." Close to $300bn in upstream deals were signed in the US over the past two years and this has whittled down the list of remaining targets. But the largest producers may not be done when it comes to seeking out potential acquisitions. "We don't stop looking," ConocoPhillips vice-president and treasurer Konnie Haynes-Welsh told the Rice Energy Finance Summit on 15 November. "We're always looking to be opportunistic." By Stephen Cunningham Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Atlantic LNG: US fob prices edge lower

06/12/24

Atlantic LNG: US fob prices edge lower

London, 6 December (Argus) — Fob LNG prices for loadings in the US Gulf coast slipped on Friday, adding to losses posted over Wednesday-Thursday to end the week lower. The Argus Gulf Coast (AGC) January fob price fell to $13.81/mn Btu, from $13.90/mn Btu a day earlier, and $14.16/mn Btu at the end of last week, following similar losses in European delivered markets. But the price continued to track European des prices, as the inter-basin arbitrage for US January loadings held shut with European markets holding at a discount to Asia that was too tight to cover the additional spot freight costs — which have been buoyed by a recent small rise in prompt spot charter rates over this week. The ARV3 prompt rate for US-northeast Asia by tri-fuel diesel-electric (TFDE) carriers was assessed at $14,000/d on Friday, up from $12,000/d a week earlier, while the corresponding ARV6 two-stroke rate rose to $28,500/d on Friday from $24,000/d. US LNG production this week has been steady at six of the country's operational liquefaction terminals. But Texas' 17.3mn t/yr Freeport LNG export terminal experienced a trip at its first of three liquefaction trains on 4 December, because of an unspecified issue at a compressor system, according to a state regulatory filing by the facility. That said, the terminal's feedgas receipts quickly rebounded a day later to reach 2.02bn ft³ over the day — the most received by the terminal since 13 November. Freeport was nominated to take 2.12bn ft³ on Friday, though the terminal has historically taken less at times than it has initially nominated to receive. Even with one day of downtime at a single train this week, Freeport's gas receipts were still greater than during the previous week, when deliveries over the opening three days of the week were also at levels suggesting one train of off line. Deliveries to the planned 27.2mn t/yr Plaquemines terminal — set to be the US' eighth liquefaction terminal — have held at low levels, suggesting that the facility may still be only receiving enough gas to meet its on-site needs rather than fully starting liquefaction operations. The 174,000m³ Venture Bayou remained at the facility on Friday, where it has been since mid-November. Plaquemines received a cool-down cargo in late September, for which it has regulatory approval to re-export, as well as a further two cool-down cargoes that have not been delivered to the facility. Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Republicans weigh two-step plan on energy, taxes

06/12/24

Republicans weigh two-step plan on energy, taxes

Washington, 6 December (Argus) — Republicans in the US Congress are considering trying to pass president-elect Donald Trump's legislative agenda by voting first on a filibuster-proof budget package that revises energy policy, then taking up a separate tax cut bill later in 2025. The two-part strategy, floated by incoming US Senate majority leader John Thune (R-South Dakota), could deliver Trump an early win by putting immigration, border security and energy policy changes into a single budget bill that could pass early next year without Democratic support. Republicans would then have more time to debate a separate — and likely more complex — budget package that would focus on extending a tax package expected to cost more than $4 trillion over 10 years. The legislative strategy is a "possibility" floated among Senate Republicans for achieving Trump's legislative goals on "energy dominance," the border, national security and extending tax cuts, Thune said in an interview with Fox News this week. Thune said he was still having conversations with House Republicans and Trump's team on what strategy to pursue. Republicans plan to use a process called budget reconciliation to advance most of Trump's legislative goals, which would avoid a Democratic filibuster but restrict the scope of policy changes to those that directly affect the budget. But some Republicans worry the potential two-part strategy could fracture the caucus and cause some key policies getting dropped, spurring a debate among Republicans over how to move forward. "We have a menu of options in front of us," US House speaker Mike Johnson (R-Louisiana) said this week in an interview with Fox News. "Leader Thune and I were talking as recently as within the last hour about the priority of how we do it and in what sequence." Republicans have yet to decide what changes they will make to the Inflation Reduction Act, which includes hundreds of billions of dollars of tax credits for wind, solar, electric vehicles, battery manufacturing, carbon capture and clean hydrogen. A group of 18 House Republicans in August said they opposed a "full repeal" of the 2022 law. Republicans next year will start with only a 220-215 majority in the House, which will then drop to 217-215 once two Republicans join the Trump administration and representative Matt Gaetz (R-Florida) resigns. By Chris Knight Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Shell, Equinor to create biggest UK producer: Update

05/12/24

Shell, Equinor to create biggest UK producer: Update

adds details throughout London, 5 December (Argus) — Shell and Norway's state-controlled Equinor plan to combine their UK upstream businesses into a joint venture to create the UK North Sea's largest oil and gas producer. The new business will produce more than 140,000 b/d of oil equivalent (boe/d) from 2025, the companies said. Bank analysts reckon growth projects will enable production to eventually increase beyond 200,000 boe/d. It marks the latest deal in a wave of consolidation in the the UK sector of the North Sea, including Italian firm Eni's deal earlier this year to merge its UK upstream assets with those of independent producer Ithaca Energy and UK company Harbour Energy's tie-up with Germany's Wintershall Dea last year . Shell and Equinor are following a similar 50:50 ownership structure and self-financing model that BP and Italy's Eni employed in Angola when they combined their offshore assets there to create Azule Energy in 2022 . The Shell-Equinor joint venture's assets will include Equinor's stakes in the Mariner and Buzzard fields, alongside Shell's interests in Shearwater, Penguins, Gannet, Nelson, Pierce, Jackdaw, Victory, Clair and Schiehallion projects. A consequence of the deal is that Shell, having walked away from Ithaca's contentious Cambo oil project in the UK's west of Shetlands area last year, will now be exposed to Equinor's equally controversial 300mn bl Rosebank project , which is currently under judicial review . If Rosebank goes ahead, it is likely to be the largest growth driver of the new company with around 70,000 boe/d of production from 2027. Although Shell's assets will contribute a greater share of the joint venture's production to begin with, Equinor's assets have greater growth potential. Through the new entity, Shell will also benefit from Equinor UK's £6bn ($7.6bn) of tax losses. "Equinor's higher UK tax loss position and growth potential offsets the higher current production in Shell's UK portfolio, hence the 50:50 split in ownership of the new company," Barclays analysts wrote in a note. The deal does not include Equinor's assets that straddle the UK's maritime border with Norway — Utgard, Barnacle and Statfjord. Equinor will also retain ownership of its UK offshore wind portfolio, as well as other low-carbon and gas storage assets. Shell will retain ownership of its interests in Scotland's Fife NGL plant and St Fergus Gas Terminal, as well as floating wind projects under development. It will also remain the technical developer of the Acorn carbon capture and storage (CCS) project in Scotland. By Jon Mainwaring Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Australia’s Woodside inks Bechtel EPC for Louisiana LNG

05/12/24

Australia’s Woodside inks Bechtel EPC for Louisiana LNG

Sydney, 5 December (Argus) — Australian independent Woodside Energy has signed an engineering, procurement and construction (EPC) contract with US engineering firm Bechtel for its Louisiana LNG terminal located in the US Gulf region. Bechtel has maintained operations at the partially constructed site since Woodside took over the project in October, after acquiring US LNG developer Tellurian , with works to continue subject to a limited notice to proceed under contract revisions, Woodside said. The Louisiana LNG foundation development comprises phases 1 and 2, which total 16.5mn t/yr capacity across three trains. Originally named Driftwood, Louisiana has permitting for a total five-train, 27.6mn t/yr capacity, with a final investment decision (FID) for phase 1 planned for January-March 2025. "In a short period of time, we have completed the acquisition, secured competitive revised EPC pricing that covers all three trains and opened the data room with strong interest from potential project partners," chief executive Meg O'Neill said on 5 December. Analysts have identified Tokyo Gas as a potential project partner, with RBC Capital Markets' Gordon Ramsay describing Louisiana LNG as a "good fit" with the Japanese utility's strategy of diversifying long-term offtake and locking in US gas supply, most recently through its purchase of independent Haynesville shale producer Rockcliff Energy for $2.7bn last year. First LNG at Louisiana is expected ahead of the project's US Federal Energy Regulatory Commission approval, expiring on 30 June 2029, O'Neill told an investor call in July, saying such a timeframe was consistent with a first quarter of 2025 FID. Perth-based Woodside heralded its fully permitted status when it announced it would buy Tellurian in July . But the election of Donald Trump as US president means a pause on issuing LNG export permits to non-free trade agreement nations is expected to be lifted in 2025 . Under O'Neill, Woodside has moved to increase its exposure to Atlantic basin LNG, inking a sales and purchase deal with the 9.5mn t/yr Commonwealth LNG in addition to an offtake deal with the 17.4mn t/yr Corpus Christi LNG in 2014. This adds to its existing 10mn t/yr equity production on Australia's west coast. Louisiana LNG expenditure from December to the end of March will be $1.3bn, Woodside said, estimating forward costs for the initial stage will be $900-960/t, unchanged from the figure at acquisition. By Tom Major Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Business intelligence reports

Get concise, trustworthy and unbiased analysis of the latest trends and developments in oil and energy markets. These reports are specially created for decision makers who don’t have time to track markets day-by-day, minute-by-minute.

Learn more