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Growing IPO pipeline revives interest in oil and gas

  • Market: Crude oil, Natural gas
  • 21/10/24

A recent flurry of initial public offering (IPO) announcements by US oil and natural gas firms, driven by lower borrowing costs and higher commodity prices, signals a modest revival of investor appetite for a sector that has long been out of favour.

Denver-based natural gas producer BKV made its trading debut on the New York Stock Exchange last month after raising $270mn, while Appalachian-focused Infinity Natural Resources has also filed to go public. Oil field services firms are also getting on in the act with HMH, backed by Baker Hughes and Norway's Akastor ASA, filing to sell shares.

Energy companies are looking to take advantage of cheaper capital after the US Federal Reserve embarked upon its long-awaited cycle of interest rate cuts, with some possibly hoping to squeeze in share sales ahead of November's presidential election. Record highs for US benchmark indexes have also fuelled positive momentum, as well as an oil market that has been lifted by the escalating tensions in the Middle East, and US natural gas prices that have bounced off their recent lows.

While price volatility has acted as a brake on the IPO market for oil and gas in the past, the hope is that pent-up demand is ready to be tapped as Wall Street slowly comes around to a sector that has spent the years since the pandemic repairing balance sheets after past excesses. An industry previously shunned by environmentally focused investors is now seeing signs of renewed engagement. And as the IPO climate improves, firms that show solid growth prospects and the ability to turn a profit will be among those that are most attractive.

"We're going to see more people hitting the markets, whether it is traditional capital markets activity, but also more IPOs," law firm Baker Botts' corporate department chair, Samantha Hale Crispin, predicts. "Being able to access the capital markets provides name recognition, access to a broader type of capital, and flexibility."

BKV listed its shares almost two years after first unveiling plans to go public. The largest gas producer in Texas' Barnett Shale basin, with operations also in the Marcellus shale in Pennsylvania, BKV sold 15mn shares at $18 apiece. That was slightly lower than the proposed price of $19-21. Infinity, which is backed by Pearl Energy Investments and Natural Gas Partners and operates more than 120 wells across 90,000 acres in the Utica and Marcellus shale basins, has also filed. And Peak Resources, an oil and gas producer active in the Powder River basin of Wyoming, is also gearing up for an IPO, according to a recent filing with the Securities and Exchange Commission.

Private exit

Despite the uptick in energy IPO announcements, there is some scepticism that the market is finally about to turn a corner, given speculation that some companies with robust cash flows are merely exiting for their private owners, with the run-up in oil prices providing the window needed. And given a pick-up in the wider IPO market, it is only natural to see oil and gas receive a boost as well.

"For private equity to exit is probably driven as much by the current status of the market, which is up a bit because of the rate cuts, and the fact that these companies are ageing in their portfolios," University of Houston energy economist Ed Hirs says. However, others see momentum behind the recent IPO announcements that is likely to gain traction once the US election is out of the way, and scope for more deals in 2025. "Sitting on capital for too long is never a good thing, regardless of which type of industry player you are," Crispin says. "There's a real desire to put that to work."


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25/10/24

Pemex budget cuts freeze vendor orders

Pemex budget cuts freeze vendor orders

Mexico City, 25 October (Argus) — Mexico's state-owned company Pemex stopped requesting or receiving new work orders from vendors in the past three to four weeks, likely linked to the company's plan to cut its budget by about $1bn in the last quarter, three industry sources and a Pemex source. "Upper management has issued clear instructions: No new projects until 2025," one Pemex source told Argus . Vendors report that these reductions are affecting all Pemex regions, with significant impacts on major well maintenance — such as pipeline renewals, valve replacements and secondary recovery techniques — essential for safe and efficient oil production. Without these services, oil service companies may need to shut down wells, risking oil spills or even explosions. The halt in work orders took effect in late September and has primarily hit orders related to maintenance in Pemex's exploration and production (E&P) operations. According to vendors, Pemex issued an internal directive on 11 October, instructing units to implement budget reductions across all E&P activities to save an estimated $1bn. Despite these cuts, vendors claim Pemex's new administration has not formally notified them about the halt — a pattern they say has become typical over the last six years. Adding to vendors' worries is Pemex's ongoing payment backlog. As of 2 October, Pemex's upstream division (PEP) owed Ps99bn ($5bn) to suppliers, with Ps81bn related to 2024 projects, Ps10.5bn from 2023 and Ps1.9bn from 2022, according to an internal document. Pemex's overall overdue payments peaked at Ps126.4bn in July. "The current situation is extremely worrisome," one Pemex supplier told Argus . "And there is no indication thatthere will be any new payments to vendors this month." Some top vendors, including Protexa, Marinsa, Naviera Integral and Solar Turbines, are weighing partial or complete work stoppages by early November unless payment issues are resolved. Drilling company Opex recently announced a "temporary adjustment" in its services because of payment delays, two other vendors said. A year ago, Pemex vendors discussed a general halt over similar payment delays, with some major suppliers like SBL, Halliburton, Weatherford and Baker Hughes eventually securing payments and continuing work. Now, with budget cuts looming into 2025, vendors are increasingly concerned that continued cuts and payment delays will severely impact Pemex's oil production, which hit a 40-year low of 1.45mn b/d in September. By Édgar Sígler Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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Pennsylvania drilling drops to 17-year low


25/10/24
News
25/10/24

Pennsylvania drilling drops to 17-year low

New York, 25 October (Argus) — Pennsylvania oil and natural gas drilling this week fell to the lowest in 17 years, signaling dimming producer sentiment in the second-largest US gas producing state. The number of rigs drilling for oil and gas in Pennsylvania this week fell to 12, the lowest since July 2007, as the state's rig count lost one from a week earlier and fell by 10 from a year earlier, according to oil field services company Baker Hughes. There were 101 gas-directed rigs in the US this week, down by 16 from a year earlier, implying that the majority of the gas-rig decline was due to the drop in Pennsylvania, where wells produce plentiful dry gas but little crude and natural gas liquids (NGLs). The 17-year-low rig count in the regional gas-producing powerhouse, home to the prolific Marcellus shale, is due to three factors: expectations of lower US gas prices after the 2024-25 winter heating season, a lower share of currently more profitable crude and NGLs in Pennsylvania's output compared to nearby West Virginia and Ohio, and the June start-up of a new gas pipeline in West Virginia , where some Pennsylvania production may have shifted. Rig counts reflect expected prices roughly six months in the future, accounting for the lag between when the drilling of a well begins and when its production is sold. The April 2025-March 2026 strip price at the Leidy Line trading hub, a bellwether for Marcellus shale output in northeast Pennsylvania, was $2.63/mmBtu, according to Argus forward curves. Prices for crude and NGLs in 2024 have been more resilient than US gas prices, which have languished after a warmer-than-normal 2023-24 winter left the US gas market oversupplied. This price dynamic may be why the other two main Appalachian gas producing states have not mirrored Pennsylvania's drilling slowdown. The Ohio rig count rose by one this week to 10, the same number as a year earlier, while the West Virginia rig count was unchanged at 10, up by three from a year earlier. Drilling productivity has also improved dramatically in the past 17 years, surging to 21 Bcf/d (595mn m³/d) in July from 471mn cf/d in July 2007, according to the US Energy Information Administration. Above-average temperatures were expected to blanket the US from November to January, according to the National Weather Service, portending another winter with lower gas demand. By Julian Hast Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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UK summer LNG imports at long-term low


25/10/24
News
25/10/24

UK summer LNG imports at long-term low

London, 25 October (Argus) — The UK received the fewest number of LNG cargoes in April-September since 2008, when it had just one commissioned LNG import terminal. The UK's three LNG terminals — 5.6mn t/yr Dragon, 15.6mn t/yr South Hook and 14.8mn t/yr Isle of Grain — together received 24 cargoes in April-September, down from 41 over the same period in 2023 and 104 in 2022. The UK's summer LNG imports were previously below 30 only twice since all three facilities have been on line — in 2018 and 2019 when 26 and 28 LNG deliveries were completed, respectively. The origin of the UK's LNG was also the least diverse since 2017, coming from just five countries. Dragon received exclusively US cargoes, while South Hook took cargoes from the US and Qatar. Isle of Grain received LNG from the US, Algeria, Norway and Peru. The UK received LNG from six countries in 2023, 2021 and 2020, and from nine countries in 2018 and 2019. Its most diverse summer of supply was in 2022, when the country received LNG from 10 countries. South Hook — owned by a joint venture between Qatargas, ExxonMobil and Total — was the only terminal to receive Qatari LNG this summer, while in previous years all three UK terminals had taken Qatari cargoes. And South Hook received just five Qatari cargoes in April-September, the lowest since the commissioning of all three terminals. This was down from 12 in summer 2023 and 39 in 2022. Qatar had constituted more than half of the UK LNG mix in 2019-20 and was the dominant supply source in 2010-17. Part of the reason for slower Qatari deliveries to South Hook may have been the effective closure of the Suez Canal route. All five Qatari vessels that delivered to the UK went the longer way around the Cape of Good Hope. The need for a change in route — triggered by Yemen's Houthi militants' attacks on ships — almost doubled the journey time. And no firms hold long-term Qatari contracts that specify UK ports as the exclusive destination point. Europe's demand for LNG was consistently weak over the summer because of low injection demand and strong Norwegian pipeline supply. Asian demand, in contrast, was strong enough to keep the arbitrage between the Atlantic and Pacific basins mostly open. And the NBP front-month market held below the TTF on all but one day over the summer, which priced out UK terminals relative to those in continental Europe. The additional buildout of LNG import capacity in northwest Europe since 2022 has significantly reduced the UK's role as an LNG transit country. In the 2022 and 2023 summers, when more LNG arrived in the UK, exports to continental Europe through the Interconnector and BBL pipelines were much higher. Interconnector flows to Belgium fell to 21.2mn m³/d in April-September, from 29.2mn m³/d in 2023 and 54.6mn m³/d in 2022. BBL deliveries to the Netherlands were roughly unchanged from a year earlier but fell by around 5mn m³/d from 2022. The Argus NBP everyday price held below the TTF throughout the past summer, apart from five days in late April and one day in early May. In addition, British consumption continues to decline. UK demand — excluding storage injections — fell to 98.1mn m³/d in April-September, from 109.5mn m³/d over the same period in 2023, 130.6mn m³/d in 2022 and 142.8mn m³/d in 2021. The continuing decline in domestic production was mostly offset by higher Norwegian pipeline deliveries. Norwegian flows to the UK through Gassco infrastructure averaged 64.6mn m³/d in April-September, up from 38.8mn m³/d in summer 2023 and 63mn m³/d in 2022. By Alexandra Vladimirova Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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Moldovan gas liquidity increase to be slow: BRM Est


25/10/24
News
25/10/24

Moldovan gas liquidity increase to be slow: BRM Est

London, 25 October (Argus) — Gas trading liquidity on Moldova's BRM Est platform will "certainly increase" but it is likely to be a slow process, BRM Moldova country manager Ion Lupulescu told Argus . One of the main issues inhibiting stronger participation from international companies is the need for them to set up a local legal entity, which entails "considerable operational costs", Lupulescu said. This is an unnecessary condition that "complicates the process and prevents the formation of liquidity in the wholesale market", he said. The lack of fully-enacted balancing market laws is another key limiting factor for liquidity, according to Lupulescu. Moldovan transmission system operator (TSO) Vestmoldtransgaz has proposed some provisional balancing rules but many aspects are still yet to be resolved, Lupulescu said. BRM proposed that the balancing platforms used in Romania should be offered to the Moldovan TSO free of charge, but Vestmoldtransgaz is yet to make a decision on this. The use of BRM's balancing platform would simplify the process by allowing the TSO and market participants to sell and buy the required quantities in real time, according to Lupulescu. Balancing in Moldova is done at the end of the month rather than each day at present, in a "very rudimentary procedure" without a balancing platform that is open to network users, Lupescu said. This process is influenced by the working method agreed by Vestmoldtansgaz with TiraspolTransgaz, the TSO from Transnistria, he added. Full balancing legislation is scheduled to be implemented in August 2025. The provision of clearing services is also on the agenda, with these services often being seen by trading firms as critical to ensuring the viability of trading, particularly in relatively small and illiquid markets. BRM has its own clearing service in Romania but is unable to provide this to its Moldovan subsidiary because there is no Moldovan legislation to enable it, Lupulescu said. BRM plans to offer these services first on the spot market and then as soon as possible on the term market, but this will only happen when the government enables it, potentially in the second half of 2025, he said. Despite these difficulties, there are some positive signs for BRM Est liquidity for the future, notably the obligation for large companies to procure their gas on the free market from the start of 2025. This will drive the development of the retail gas market in Moldova, although liquidity will only increase if there are "more active traders on the wholesale market", Lupulescu said. Lupulescu expects Moldovan consumption to increase in the coming years, but said this will depend on investments from industrial users, economic development and energy efficiency measures, among other factors. Once Moldovan legislation aligns with EU laws, BRM hopes to start offering further services for products such as green gases and guarantees of origin, if there is market demand. The first spot transaction was carried out on BRM Est's platform on 30 September and the country's largest supplier Moldovagaz completed its first spot transactions last week . Liquidity has increased over the past five days, with around 20 GWh/d traded by companies buying gas on BRM in Romania and then trading this gas on BRM Est's spot market, Lupulescu said. Prices averaged around €39.70/MWh, he said — lower than Argus' assessment of the TTF day-ahead market which averaged €41.01/MWh on 21-24 October. By Brendan A'Hearn Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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India’s Petronet calls Dahej regas tariff “reasonable”


25/10/24
News
25/10/24

India’s Petronet calls Dahej regas tariff “reasonable”

Mumbai, 25 October (Argus) — 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 Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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