The CME/NYMEX Henry Hub prompt natural gas futures prices have been relatively rangebound this injection season and have averaged around $2.60/MMBtu since June — a third or less of where prices stood during the same period last year, in the $7-$9/MMBtu range, and at or below most natural gas producers’ breakeven costs. Yet, this is a much rosier scenario than it could have been considering that the first quarter of 2023 was one of the most bearish in over a decade and led to a massive storage surplus vs. last year that persisted through much of the summer. Since setting the year-to-date monthly average low of $2.19/MMBtu in April, prompt futures rose to an average of nearly $2.50/MMBtu in June, ~$2.65/MMBtu in July and August, and have mostly stayed in the $2.50-$2.75 range in September to date. In today’s RBN blog, we break down the factors that kept prices from unraveling this injection season to date and the implications for the rest of the shoulder season.
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After being relegated to the back burner during the shale boom, the natural gas storage market is showing signs of a comeback. Market participants are clamoring for storage solutions, storage values are rising, and storage deals and expansions are bubbling up. However, that won’t necessarily lead to a widespread build-out of new storage capacity like the one that transpired in the pre-shale storage heyday of the mid-to-late 2000s. That’s because the world has changed, and what’s driving storage values today is vastly different than what drove the last big capacity build-out. In today’s RBN blog, we look at the emerging developments in the storage market, what’s driving them, and the implications for Lower 48 storage capacity.
It took an “Act of Congress” and a decision from the highest court in the land — handed down by the Chief Justice no less — but it’s looking more and more like Mountain Valley Pipeline (MVP) will be completed as early as by the end of this year, opening up 2 Bcf/d of new takeaway capacity for the increasingly pipeline-constrained Appalachian gas supply basin. That’s shifted the industry’s gaze to bottlenecks downstream of where the bulk of the volumes flowing on the new pipeline will land — on the doorstep of Williams’s Transco Pipeline in southern Virginia. A number of midstream expansions have been announced to capture the influx of natural gas supply from MVP and shuttle it to downstream markets in the Mid-Atlantic and Southeast regions, and indications are that more will be announced and greenlighted in the coming months. These projects will be key to both enabling gas production growth in the Appalachia basin as well as meeting growing gas demand in the premium markets lying on the other side of the constraints. In today’s RBN blog, we delve into the details and timing of the announced expansion projects vying to increase market access to MVP supply.
With the Mountain Valley Pipeline (MVP) project clearing some major legal hurdles in recent weeks and construction resuming, it’s become increasingly likely that Appalachian gas producers will soon have 2 Bcf/d of new takeaway capacity, potentially as early as late 2023. However, the degree to which the pipeline will translate into higher production from the supply basin and improved supply access for the gas-thirsty, premium markets in the Southeast will largely depend on the availability of transportation capacity downstream of MVP. As such, the race is on to expand pipeline capacity from the pipe’s termination point at Williams’s Transco Pipeline Station 165 in southern Virginia, not only to deal with the impending influx of supply from MVP but also to move that gas to growing demand centers in Virginia and the Carolinas. MVP’s lead developer, Equitrans Midstream, is hoping to build an extension to the mainline — the MVP Southgate project — while Transco has designs of its own for capturing downstream customers. In today’s RBN blog, we provide an update on MVP and the various expansion projects in the works to move newly available supply to market.
The bulk of the second wave of U.S. LNG export projects will be situated along a small stretch of the Gulf Coast, from Port Arthur at the Texas-Louisiana border to the Mississippi River in southeastern Louisiana. Three of these projects — Golden Pass LNG, Port Arthur LNG and Plaquemines LNG — are under construction there and will add nearly 7 Bcf/d of new gas demand by 2028, and others could reach a final investment decision (FID) in the coming months or years. That’s prompted a frenzy of natural gas pipeline projects vying to serve this growing demand center, whether by moving incremental supply into the area or providing “last mile” delivery to the terminals. These pipeline expansions — and how well the incremental capacity, geography and timing align with liquefaction capacity additions — will drive the pace of overall gas demand growth and how the Lower 48 gas market will balance in the coming years. In today’s RBN blog, we discuss highlights from our new Drill Down Report detailing the slew of announced pipeline projects targeting LNG exports from the Port Arthur, TX/Louisiana region.
Even an “Act of Congress” may not be enough to keep the Mountain Valley Pipeline out of trouble. The long-stalled natural gas takeaway project in Appalachia briefly appeared to be unfettered from regulatory and legal shackles after Congress rolled an MVP mandate into the debt-ceiling bill — the Fiscal Responsibility Act (FRA) of 2023. With the MVP provision, Congress effectively approved all required permits for the greenfield project without judicial review in a bid to fast-track the completion and initial startup of the pipeline. The FRA, which President Biden signed into law on June 3, appeared to instantly clear MVP’s path. But that reprieve didn’t last long. Earlier this week, the U.S. Fourth Circuit Court of Appeals once again halted construction of the project, seemingly in defiance of the FRA, setting the stage for a fight at the Supreme Court. In today’s RBN blog, we break down the latest developments and how they impact MVP’s prospects.
The Fiscal Responsibility Act (FRA) revived Mountain Valley Pipeline’s (MVP) prospects of being completed this year, but the outlook for new, large-scale natural gas takeaway projects in the Northeast beyond MVP hasn’t changed. What has changed, however, is how Appalachian natural gas-focused producers respond to pipeline constraints and lower prices. Gone are the days of drilling with abandon, crushing supply prices and assuming the necessary pipeline capacity will eventually get built. Instead, producers have demonstrated a willingness to slow drilling activity, delay completions and choke back producing wells in the short-term to manage their inventory during periods of lower gas prices. In today’s RBN blog, we lay out our view of what that shift in producer behavior will mean for Northeast supply, demand and pricing trends in the long-term.
Last summer, a tight coal market in the Eastern U.S. made an already tight natural gas market even tighter. Low coal stocks, dwindling production and transportation constraints led to exorbitant premiums for Appalachian coal and limited coal consumption in the East, leading to record gas demand for power generation — even as gas prices soared to 14-year highs. Now, gas markets are considerably looser, storage inventories are high, and gas prices are signaling the need for more demand (or lower supply) to balance the market and avoid storage constraints this injection season. But the coal market has eased as well. Coal production is up, coal stocks are too, and Appalachian coal prices have plunged in recent months. What will that mean for power burn and balancing the gas market this summer? In today’s RBN blog, we look at the latest developments in the coal and gas markets, the potential for coal-to-gas switching, and how those dynamics could impact gas balances.
New U.S. LNG export projects battling rising labor and equipment costs and/or financing woes have one more thing to worry about that the first wave of projects didn’t: ensuring the feedgas supply will be there when they need it. Bottlenecks have already developed for moving natural gas volumes to the Louisiana coast, where the bulk of future export capacity will be sited. As more liquefaction capacity is built out and more export projects are greenlighted, a lot more pipeline capacity will be needed to move feedgas supply from the Haynesville and other supply basins into southern Louisiana and across the last mile to the terminals. In today’s RBN blog, we conclude our roundup of pipeline expansions in the Bayou State that would help ease transportation constraints and balance the market, this time with a look at announced-but-yet-to-be sanctioned greenfield pipeline expansions, along with an update on their associated export projects.
The U.S. won’t add new LNG export capacity this year for the first time since it became an exporter in 2016. But that lull is not going to last long. At least five facilities are under construction and due for completion in the next few years, several other expansions were recently sanctioned, and there are more final investment decisions (FIDs) on the way. With export development expected to accelerate in the coming years, the race to debottleneck feedgas pipeline routes is on. More natural gas pipeline capacity will be needed, particularly for moving gas supply to the Louisiana coast, where the bulk of new liquefaction will be sited. In today’s RBN blog, we resume our series on the pipeline expansions targeting LNG export demand, this time highlighting TC Energy’s Gillis Access Project and how it fits into the Louisiana LNG market picture.
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.
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.
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.
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.
