US gas price volatility likely to continue

Market: Natural gas
28/03/23

The past 18 months have been a wild ride for natural gas prices, as well as for the bottom line of investors and companies that are subject to their gyrations.

Spot prices in production and demand centers of the US have broken volatility records in recent months, while producers have reversed their course on hedging as gas prices collapsed.

The next few years portend more of the same.

"I think volatility is here to stay for the foreseeable future," Citi analyst Paul Diamond told Argus. "The underlying issues causing that step change in the last 24 months are not going away."

If one measures volatility by the number of days an asset moves by more than 7pc in value, 2022 was the most volatile year for natural gas prices since at least the beginning of the shale era. In 2022, the price for day-ahead delivery at the US benchmark Henry Hub in Louisiana rose or fell by more than 7pc on 65 occasions, the most of any year since at least 2009, according to an Argus analysis.

So far, the Henry Hub has done so 21 times this year. At that rate, 2023 will be more volatile than 2022.

How volatility returned to gas markets

After the shale revolution of the 2000s brought cheap and efficient techniques for increasing domestic gas production, including horizontal drilling and hydraulic fracturing, or "fracking," US gas prices enjoyed a long decade of low volatility. On average, the US benchmark only moved by more than 7pc on 17 days/yr between 2009-2021 — about one-third the 2022 rate.

That period of relative price stability ended sometime around the fourth quarter of 2021 when prices rose on an unexpected increase in power demand and record-high LNG exports. Despite tight supplies and high prices, producers mostly stuck to their promises to investors to maintain capital discipline, declining to increase production at pace with demand.

Producers stuck to their script even when Russia invaded Ukraine in 2022, threatening gas supply to Europe and causing a global energy crisis in which overseas appetite for US gas soared, lifting prices even higher.

The prompt-month price — the price for delivery of gas every day in the following calendar month — for the Henry Hub in December 2021 averaged $3.86/mmBtu. In May 2022, the price was more than twice as high, at $8.16/mmBtu. It averaged over $7/mmBtu in subsequent months, peaking at $9.68/mmBtu on 22 August, the highest since 23 July 2008.

When the 2 Bcf/d (57mn m3/d) Freeport LNG export terminal in Texas went off line in June after a fire, record-high gas consumption kept prices afloat even as domestic supply instantly increased. When the consumption leveled off as cooling demand fell, however, prices began to fall, insulated from the overseas chaos by an absence of LNG export capacity. The price drop accelerated when the US experienced historically low heating demand in January and February, pushing inventories from a deficit to a surplus to the five-year average.

In the two months ended yesterday, the Henry Hub prompt-month price averaged $2.47/mmBtu.

Why volatility could be here to stay

While some of the volatility of recent months has been because of unforeseen events — the war in Ukraine, the fire at Freeport LNG, historically mild weather — much of the volatility to come is expected to arise because of structural uncertainty currently being built into the gas market.

One piece of that uncertainty is what price crude oil and gas will be fetching when LNG export terminals begin coming on line in late 2024 and beyond. For example, if oil prices are low and producers in the Permian respond by pulling back on drilling, that will reduce associated gas production, which could starve LNG terminals. Low gas prices could also reduce production in the Haynesville, which would be hard to make up for in the Marcellus and Utica shales, where pipeline takeaway capacity limits production growth.

If LNG terminals are delayed, prices could plunge as domestic supply races ahead of demand.

"As we add more LNG demand along the Gulf Coast, the timing between LNG facilities, the pipelines to feed them, and the production to meet the new demand all has to be in sync," BTU Analytics analyst Connor McLean told Argus. "If the timing slips for any of those pieces, we are likely to see the market react strongly until the other pieces catch up."

On top of the uncertainty, the steady retirement of coal-fired power plants has reduced the ability of electrical utilities to switch from coal to gas when supplies of one or the other are constrained. And while gas consumption continues to rise, regional opposition to the construction of new pipelines has led to a slowdown in expansions of pipeline capacity.

The increased reliance on gas can make market participants react more strongly to price signals than they would have otherwise.

By Julian Hast

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Cop: G20 momentum key to Cop climate finance outcome

18/11/24

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Cop: G20 momentum key to Cop climate finance outcome

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Q&A: Chevron sees global exploration revival

18/11/24

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18/11/24

Q&A: Chevron sees global exploration revival

London, 18 November (Argus) — US major Chevron and its peers are taking a more prominent role in global frontier exploration as they push for scale and value in oil and gas output in the face of an uncertain energy transition. Chevron vice-president of global exploration Liz Schwarze spoke to Aydin Calik at the African Energy Week conference in Cape Town, South Africa, earlier this month, Edited highlights follow: How much of a role do you think exploration will play for Chevron and the wider sector in the next 10 years? We believe the future of energy is lower carbon, and we're leveraging our strengths to grow energy delivery to an energy-hungry world. We see oil and gas being part of the energy mix for longer, investing to reduce the carbon intensity of our existing operations. Growing our oil and gas for longer, because it's a declining business — as you produce it, you have to replace it. We replace our resources to underpin our future in three ways. Exploration is one; M&A, buying other companies, is another; and then technology is the third. So think in terms of shale and tight development in the US, with drilling and completions technologies; and the Anchor technology, bringing on the world's first 20k [20,000 lb/inch², ultra-high pressure deepwater] production platform in the Gulf of Mexico. That's technology. It's a new development, but it will help in the long term. For exploration, at Chevron, we invest in exploring in our existing assets — if we can find new oil and gas pools that we can tie into existing infrastructure, it's a win... it comes on faster, creates a lot of value, leverages existing infrastructure — but we're [also] increasing our investment in more frontier areas, where we can build big, material positions at scale, early and if successful, really build new businesses. That's what you see us doing in places we've added acreage recently, like Brazil and Uruguay. We have the block in Namibia, we're going to drill, and we're in Egypt and so forth. So exploration is a very important part of Chevron's future, and because it's a bit of a long-cycle game, yes, for exploration, 10 years is an easy horizon. And do you think things might change in terms of what you're exploring for — more oil, more gas? Oil is relatively straightforward to get to markets, because there's a global market for liquids. If we're going to explore for gas, it'll be in a place that has either an existing market or existing assets to market, for the most part. Sometimes you explore for oil and you find gas. Sometimes search for gas and you find oil — because it's model based particularly in these frontier areas. So, you know, whatever mix we find we have to look at the development scenario for that, so that we can bring as much of that product to market with the highest returns possible for our shareholders. What are the biggest challenges for explorers today? We'll focus on the frontier first. Chevron looks at entering a new country or a new basin for exploration, really looking for four things to be there. First, of course, are the rocks — a compelling hypothesis that there are hydrocarbons at commercial scale. Second is a supportive fiscal environment, with which, upon discovery, you'd have the opportunity to create value for everyone. The third is access — the country has to offer a way for an operator like Chevron to enter, whether that's through a competitive bid round or through a direct negotiation; we'll also do farm-ins to other people's acreage. And regular access. That hypothesis of where hydrocarbons are can change through time. Having regular, predictable opportunities to access acreage is important, and it is sometimes a challenge. Some countries have opportunities for a while, and then they'll take things off the market, and then you don't really have another way to invest, and that creates a challenge. And then the fourth consideration is just the overall welcomeness for us to deliver the work programme that we commit to — functioning governmental organisations, all the way from environmental to operational permitting. Where is the most exciting place to explore at the moment? Are there any new Namibias around the corner? I hope so! Everywhere we enter, we have a story. Sometimes it works and sometimes it doesn't work. But we've got a well drilling in in Egypt now, so west of the Nile in the Herodotus basin — it's called the Khendjer well. So Egypt, we're excited. Namibia, it's the hot story of the past few years. In the Orange basin, we're in PEL90, and that well will start notionally [on a] December timeframe. Think of a big deepwater exploration well. Think of 90 days as an average. [We are] really very keen to see what our block holds. Certainly, high hopes. And then we've added new acreage in Brazil, the South Santos and the Pelotas basin, we signed a block last week in Uruguay. And so, you know, some of that geology is what we call conjugate margin in Namibia. And Angola and Nigeria. There are places in the world that are very successful hydrocarbon provinces that are still under explored and we think have a tremendous potential. And Nigeria deepwater is one. We had a lovely discovery on the Nigeria shelf a few weeks ago — the Meji well. And then we added two blocks in Angola earlier this year, deepwater. I'm getting a sense, not just from Chevron, that exploration around the world is picking up? I think this is true across the board. And one of the reasons that you explore is the idea that there's likely a further advantaged barrel relative to some of the existing discoveries. So there are a lot of stranded discoveries — either cost-prohibitive, geopolitically challenged, any number of issues that prevent some of the really big discoveries around the world from coming to market. From an exploration standpoint, if you are able to discover at scale, develop that and then bring it to market, it will be lower in the supply stack from a breakeven perspective. And lower carbon intensity as well from the get go, and it will find a place in the market. On Namibia, what we have heard from some other operators is high gas content. This might make it more challenging. Have you thought about that? So when we're thinking about entering a new basin, and then when we're thinking about drilling the well, before we make those investments, we're always thinking about what the development scenario might look like. Because we've got to test that development scenario against our range of resource outcomes and test, you know, whether it's going to be economically viable. Or how would we make it economically viable? So for Namibia, we have considered, what would you do at various gas contents? The first, simplest, development is that you bring your production flow to your FPSO, compress the gas and reinject it. You can do that, given the resource volumes at a commercial outcome, Over time, I think it'll be interesting to see if there's a broader-basin scale gas solution that comes to bear, whether that's pipe to shore or LNG. It depends on the GOR [gas-oil ratio] and then it'll depend upon the gas terms that the government provides. In the eastern Mediterranean, is Egypt your main exploration prospect? Our focus is Egypt for exploration. When we go into an area like Egypt, we try to pick something at scale, and then high-grade from there. And so you relinquish the leases that, with additional data, don't look as prospective as the other ones. Right now, our focus is on block four. We're going to drill, and then we're also in [a block] north of that, that someone else operates on our behalf, and we have a minority interest. What about Algeria and its shale potential? To what extent do you think you'll be able exploit those resources? And will you be signing something soon? Chevron has been in conversations with the ministry, upstream regulator Alnaft and Sonatrach since 2020. We signed MOUs, that was in the news. And then the big milestone was 13 June of this year, where we aligned on two areas of interest. And we signed heads of agreement to negotiate Chevron's entry into these two areas of interest. And so that's ongoing now, and that's all I can say about that. We have two areas, one in the Ahnet and one in the Berkine, and seeing if there's a negotiated agreement that would have Chevron enter the country, working with Sontrach to explore and develop those. Algeria is, again, one of these very hydrocarbon-rich countries in Africa. A tremendous gas resource. So we think it's a really strategic opportunity for Chevron, if we can get to a negotiated agreement that's amenable to both parties. You know, significant resources in an existing, vibrant oil and gas sector, access to markets through pipelines and LNG for the gas. And so we believe at Chevron that we can bring our global experience, and in particular our shale and tight expertise to bear in Algeria. To help them explore and ultimately develop. But you think you can do shale development there? Yes. I mean, the first piece would be exploration, right? So, you know, even in shale and tight, the molecules are there, or you're fairly confident the molecules are there. It's just, are the molecules producible at a commercial scale? And so that's always the first phase — you drill some pilots, look at your flow back, then optimise. And we believe everything that we do in the Permian is potentially applicable, especially from a factory perspective, right? And then the challenges are going to be things like supply chain. How much more exploration potential is there left in the Gulf of Mexico? Would you say, is it mature, or is it still much to play for? The Gulf of Mexico tends to reinvent itself. So we still see plenty of potential there. What's going on in the Gulf of Mexico right now are two critical technologies. One is on the geophysics side — ocean bottom node acquisition for exploration, which is giving us much better images of very complicated geology. That's a critical technology evolution. And we believe that that will help discern between prospects — point the way of where not to drill, and where maybe to drill. And then the other one is, of course, the Anchor platform, which is the world's first 20k. We are currently the only operator in the world that's operating a 20k field, and so I don't know where that technology would be applicable globally yet. But you know what we see? You've got to build the technology, you put it on production, and then you realise, oh, okay, now I can use this to really unlock some other areas. Still pretty, pretty excited about the Gulf of Mexico. Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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Hong Kong unveils green maritime fuel action plan

18/11/24

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18/11/24

Hong Kong unveils green maritime fuel action plan

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India cuts allocation to city gas firms again

18/11/24

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18/11/24

India cuts allocation to city gas firms again

Delhi, 18 November (Argus) — The Indian government has reduced the domestic gas allocation to the city gas distribution sector by state-run distributor Gail, effective from 17 November. This is the second cut after they first slashed allocation by 20pc, or 4mn-5mn m³/d , last month. The cut for Delhi-based city gas entity Indraprastha Gas is a reduction of 20pc, for Mumbai-based Mahanagar Gas it is 18pc, and for privately owned Adani Total Gas it is 13pc, the firms' stock exchange filings stated over the weekend. The move would reduce the overall share of domestic gas allocation to city gas distributing companies to 30-37pc from 50pc last month and 70pc at the beginning of the year. City gas firms had received priority status for gas allotment over the past two years. "It is uncertain what could have re-instigated this cut, but this may translate into 6.5mn-7mn m³/d based on the different growth rates of city gas firms," Moody's affiliate ICRA senior vice-president Prashant Vashisht told Argus . City gas entities are mulling a hike in CNG rates and are heard to be in talks with the government over the policy changes. The government is yet to formally announce a statement over the cuts and is heard to be asking retailers to give a cost break-up to justify the hike, sources say. These cuts are mainly aimed at compressed natural gas (CNG) supply that has been receiving domestic gas allocation at a fixed price by the government of $6.5/mn btu under New Delhi's pricing mechanism — almost half the price that firms would pay for spot LNG. City gas firms are discussing the possibility of increasing CNG prices by Rs5-5.5/kg by the end of the year to preserve their margins. This would represent a 7pc increase compared with the average CNG price of Rs75.1/kg ($0.88/kg) against Rs94.77/litre of petrol in New Delhi. But the price hike may reduce CNG's competitiveness, hampering further development of the sector and limiting LNG demand growth. CNG vehicles have rapidly expanded their share of the Indian fleet, accounting for 14pc of all four-wheelers at present, up from 8pc three years earlier, data from the government's Vahan website show. The reduction in allocation is linked to reduced supply from conventional gas fields run by state-controlled upstream companies such as ONGC and Oil India. The sector received 27.8mn m³/d of domestic gas over April-September, including about 5mn m³/d of higher-priced supply from high-pressure, high-temperature fields, oil ministry data show. Allocation to the sector was largely unchanged during the same time last year. To bridge this shortfall, city gas firms are exploring options of sourcing gas through LNG , domestically produced high-pressure and high-temperature gas, production from ONGC's new wells, and long-term gas contracts. 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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