From its origins as a specialized energy source sold under long-term, point-to-point contracts to primarily Asian destinations, LNG has become progressively more commodified as its global reach has spread, with 44 countries now importing it. An increasing proportion of cargoes are destination-flexible and can be sent to the market that offers the best price, and the marginal price of LNG is set by supply and demand factors. The spectrum of commercial players has grown and come to resemble more closely the oil market, with not only international oil companies as major participants but also traders and utility buyers, all of whom are contributing to a vibrant international LNG marketplace. But unlike oil and other established commodities, LNG lacks a global reference or benchmark price, and instead is priced regionally, with the divergence in regional market prices giving rise to very profitable arbitrage opportunities for those controlling both product and ships. In today’s RBN blog, we look at the pricing indices used to make LNG trading decisions and two initiatives being implemented by the European Commission (EC) that are intended to improve price transparency for LNG trades and prevent price spikes in European gas markets through a consortium-purchasing approach.
Natural Gas
Hardly a day goes by without news related to U.S. LNG export capacity expansions, whether it’s upstream supply deals, offtake agreements or liquefaction capacity announcements. One project is nearing commercialization, another five are under construction and due for completion in the next few years, still others are fully or almost-fully subscribed and will be officially sanctioned any day now, and the announcements keep coming. Just days ago, Venture Global reached a final investment decision (FID) for the second phase of its Plaquemines LNG project. With export development accelerating in the coming years, more natural gas pipeline capacity will be needed, particularly for moving gas supply to the Louisiana coast, where the bulk of the new capacity will be sited. In today’s RBN blog, we continue our series highlighting the pipeline expansions targeting LNG export demand, this time focusing on projects moving gas to southeastern Louisiana, including those designed to deliver feedgas to Venture Global’s under-construction Plaquemines LNG project.
Russia’s invasion of Ukraine in February 2022 caused panic in European gas markets that were already on the brink due to low winter inventories. Near-term supply/demand balances suddenly took on a heightened urgency, and everyone knew that policy and infrastructure changes were needed, pronto. The most immediate concern was the very real possibility that the winter of 2022-23 could see gas rationing within the European Union (EU) due to supply shortages. However, with winter now in retreat, Europe is emerging with record volumes of stored gas accompanied by prices that have fallen to pre-invasion levels. This is no time for complacency, though. While it’s many months away, the winter of 2023-24 looms, with dire warnings that things could be considerably worse in gas markets. In today’s RBN blog, we evaluate how European gas and LNG markets have managed over the last 12 months and discuss the implications for the next year. In particular, we look at the European Commission’s (EC) efforts to inject reforms into European gas markets, not only to accommodate supply disruptions but also to set the stage for a gas market no longer reliant on Russian supplies.
Oil and gas companies across the value chain are facing new pressures to manage and reduce methane emissions. Their ability to access premium markets and buyers, appeal to investors and avoid costly fees depends on developing a credible plan to measure and reduce methane emissions. At the very least, the industry’s regulatory outlook, its non-governmental quasi-oversight and its access to capital are changing in ways that make understanding sometimes inconsistent emissions data vitally important. In today’s RBN blog, we explore the recent changes and the mounting external pressures around methane emissions.
New England’s aggressive effort to decarbonize is a tangled web. Over the past several years, the six-state region has replaced oil- and coal-fired power plants with natural gas-fired ones but most proposals to build new gas pipeline capacity have been rejected. It’s also made ambitious plans to add renewables — especially solar and offshore wind — to its power generation mix but many of the largest, most impactful projects have been delayed or canceled. And now there’s a big push to electrify space heating and transportation, which will significantly increase power demand, especially during the winter months, when New England’s electric grid is already skating on thin ice. In today’s RBN blog, we examine the region’s looming power supply challenges and how its energy transition plans may affect natural gas, LNG, heating oil and propane markets.
As U.S. LNG export project development accelerates in the coming years, a lot more natural gas pipeline capacity will be needed to supply the numerous liquefaction facilities vying for a piece of the global gas market pie. That’s particularly true for a small stretch of the Gulf Coast from the Sabine River on the Texas-Louisiana border to the Calcasieu Pass Ship Channel — where the bulk of planned export capacity additions are concentrated — even as transportation bottlenecks are emerging for getting natural gas supply to the area. To address the growing demand, a number of pipeline expansions are planned or proposed to bring more supply into the region or deliver feedgas across the “last mile” to these multibillion-dollar facilities. In today’s RBN blog, we continue our series highlighting some of these LNG-related pipeline projects, this time focusing on ones aiming to feed exports out of southwestern Louisiana.
LNG exports will be the biggest driver of demand growth for the Lower 48 natural gas market over the next five years. After a year of oversupply in 2023, export capacity additions will help to balance the market and support gas prices in 2024 as the glut spills over into next year. Beyond 2024, higher export volumes will lead to tighter balances and price spikes. As supply struggles to keep up with new export capacity, the timing of pipeline expansions will be critical for balancing the market. The bulk of new LNG export projects are sited along a small stretch of the Texas-Louisiana coastline and more pipeline capacity will be needed to move incremental feedgas into this area and across the “last mile” to the facilities. In today’s RBN blog, we begin a series delving into the planned pipeline expansions lining up to serve LNG demand along the Gulf Coast.
Over the past five years, the North American oil and gas industry has undertaken a major strategic shift, embracing the global push to decarbonize by, among other things, emphasizing the greener emissions profile of natural gas vs. coal and taking aggressive steps to reduce the volumes of methane, carbon dioxide and other greenhouse gases emitted during the production, processing and transportation of just about every kind of hydrocarbon. It’s a real challenge, though. Operators face a seemingly endless and overwhelming set of choices about how best to approach emissions reductions, which technologies to use, which programs to join, and how to interpret new emissions-measurement data, to name a few. In today’s RBN blog, we begin a look at how operators can achieve key environmental goals while protecting — even improving — their bottom line and meeting a host of important goals, from reducing the cost of capital and managing investor pressure to improving realized prices and market access.
Natural gas production in Western Canada has been enjoying a steady revival in recent years, heavily assisted by enormous growth in the unconventional Montney gas formation. A sizable portion of this formation lies in the westernmost province of British Columbia, but also underlies a large contiguous land area in that province which has been the subject of land access and development issues with the province’s First Nations residents. As a result of a legal decision made in June 2021, future natural gas production growth was thrown into question as new well licenses, crucial for future gas well development, were placed on hold until a new agreement could be reached. In the nick of time, a new agreement was announced last month. In today’s RBN blog, we discuss the implications on future natural gas drilling and production.
The CME/NYMEX Henry Hub prompt natural gas futures price has fallen precipitously in recent months and 2023 has the potential to be one of the most bearish in recent history. But longer term, the stage is set for tighter balances, price spikes and increased volatility. After a slowdown in 2022-23, LNG export capacity additions will come fast and furious over the next several years. As they do, they will outpace production growth, which will increasingly depend on pipeline and other midstream expansions. In other words, 2023 will be the last aftershock of Shale Era surpluses. We got a taste of what that could look like in 2022, but just how out-of-whack could the gas market get? In today’s RBN blog, we discuss the supply and demand trends that will shape the gas market over the next five years.
2022 was a particularly significant year for the global LNG industry, distinguished by a sharp increase in LNG demand in Europe tied to the reduction in flows of Russian pipeline gas after Putin’s invasion of Ukraine. Whereas Europe had historically been the last market option for many LNG sellers, it became the most highly priced market in the world and pulled in LNG from multiple locations, including a cargo from Australia delivered in October. Paying premium prices enabled European buyers to fill the continent’s underground storage at an unprecedented rate — as of mid-January, storage there was over 80% full. A mild winter, at least to date, coupled with conservation efforts and fuel switching have reduced European natural gas demand by 10% to 15% and helped avoid a gas shortage. Now, gas prices (and LNG cargo prices) have fallen to pre-invasion levels and prompted market observers to suggest that, with China emerging from pandemic-related lockdowns, Asia may start pulling large volumes of LNG its way. In today’s RBN blog, we examine LNG cargo movements within the Asia Pacific and Atlantic regions and what rising Asian demand could mean for European gas supplies going forward.
Russia’s invasion of Ukraine last February upended long-standing expectations about natural gas supplies to Europe and resulted in elevated global gas prices as countries bid for LNG to fill the void. But U.S. suppliers can only produce so much LNG, and how much of it ends up in Europe versus Asia or other gas-consuming regions in 2023 and beyond will depend largely on market forces — in other words, who needs the LNG more and is willing to pay up for it. At the center of these market-based decisions about LNG cargo destinations are large portfolio players like Shell, BP, TotalEnergies and Naturgy and short-side portfolio players like Japan’s JERA. In today’s RBN blog we look at these two types of players, the roles they play, and their contributions to energy security.
The Lower 48 natural gas market has had the most bearish start to a new year in a long time. Production has been at record highs, an exceptionally warm start to January suppressed demand, and LNG exports have been hobbled since last June when Freeport LNG went offline. The CME/NYMEX Henry Hub February gas futures contract slid to an 18-month low of $2.94/MMBtu last Thursday and expired Friday at $3.109/MMBtu, down 54% from where the prompt contract closed just two months earlier. The March contract extended the slide Monday to a 20-month low of $2.677/MMBtu. Freeport’s eventual return will restore existing export capacity, but there’s no new LNG export capacity due online this year — for the first time since 2016. After one of the tightest gas markets of the last decade in 2022, the stage is set for one of the most oversupplied markets we’ve seen in years. But the bulls out there can take solace: 2023 will also mark the final throes of the kind of oversupply conditions that defined the Shale Era as we know it. In today’s RBN blog, we discuss how we got here and RBN’s outlook for natural gas supply and demand.
For the past several years, Western Canada’s natural gas producers have been forced to sit on the sidelines of too many broader price rallies as their main benchmark, AECO, languished at painfully low levels. Though an increasing number of producers have been steadily diversifying their price exposure away from Western Canada and AECO, even greater pricing upside might be captured if marketing arrangements could be developed to access higher international LNG prices via U.S. Gulf Coast terminals. In today’s RBN blog, we look at the steps that two of Canada’s largest natural gas producers have taken to capture that LNG price upside.
We can’t conjure up a more old-school, more intrinsically American industry than whiskey-making, or more iconic whiskey names than Jack Daniel’s and Jim Beam — the latter, of course, being a bourbon, a particular type of whiskey. The recipes for both “Jack” and “Jim” have remained unchanged for generations and their distillers in Tennessee and Kentucky, respectively, are traditionalists to their core. That doesn’t mean, though, that they’re unaware of the need to reduce their greenhouse gas (GHG) emissions — or are blind to the opportunities that decarbonization may present. Now, as we discuss in today’s RBN blog, both Jack Daniel’s and Jim Beam are all-in on producing renewable natural gas (RNG) from spent grains.