When it comes to midstream development in the Northeast, Appalachian natural gas producers have learned by now not to hold their breath. The region is notorious for its staunch environmental opposition to hydrocarbon infrastructure and its propensity for sending gas pipeline projects to the trash pile. Against all odds, however, midstream development in the region has thawed in recent months, in large part spurred by the unlikely advancement of Mountain Valley Pipeline (MVP), the long-embattled project to move up to 2 Bcf/d from the Appalachia gas supply basin to the Transco Corridor, which runs north-south along the Eastern Seaboard. In today’s RBN blog, we take a look at historical flows on Williams’s Transco Pipeline and what they can tell us about how MVP and Transco’s own planned expansions might reshape gas flows along the corridor.
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Appalachian natural gas producers got good news earlier this month: Williams announced it was moving forward with the Southeast Supply Enhancement project, a large-scale expansion of southbound capacity out of the Northeast on its Transco Pipeline system. Not only that, but it super-sized the project to 1.4 Bcf/d of capacity — nearly double the 800 MMcf/d it had offered in an open season held this summer. The project is one of several brownfield expansions planned to provide additional supply access in Transco’s premium Zone 5 market area, which runs through Virginia and North Carolina — and the first large-scale takeaway expansion to be announced in the area since the long-delayed Mountain Valley Pipeline (MVP) was cleared for completion following years of regulatory and legal hurdles. In today’s RBN blog, we provide the latest on the Transco Corridor expansions.
Six months ago, the U.S. West Coast natural gas market looked like it was in dire straits. A harsh winter had depleted stocks to the lowest level in over a decade and it seemed like the region would be hard-pressed to refill storage to a reasonable level, given limited and constrained pipeline options to flow incremental gas west. Instead, a combination of mild weather and operational changes eased demand and pipeline constraints, and Pacific Region storage staged a remarkable comeback this summer. In today’s RBN blog, we delve into how the region escaped a worst-case scenario heading into the heating season.
Storage has long been a critically important balancing mechanism in the Lower 48 natural gas market. Now, after languishing for much of the Shale Era, storage values are coming out of the doldrums. The key driver behind this change is that, unlike in the old days, when the storage market was driven primarily by the intrinsic value of capacity — i.e., the need to sock away gas in the lower-demand summer months for use in the peak winter months — the value of storage is being driven almost exclusively by extrinsic economics — i.e., how flexible and responsive capacity allows market participants to manage supply and demand during short-term market swings. This flexibility and responsiveness have become increasingly important criteria for ensuring reliability as LNG export facilities and an increasingly renewables-heavy power sector navigate frequent demand fluctuations day to day, or even intraday, as well as during high-stakes, extreme weather events like 2021’s Winter Storm Uri. In today’s RBN blog, we delve into the fundamental shifts influencing today’s storage market.
Appalachian natural gas producers and marketers are adapting to a new status quo — a world where new pipeline takeaway capacity out of the Northeast is hard to come by and is more or less capped ad infinitum. Without the assurance of pipeline expansions, regional gas producers are no longer drilling with abandon in hopes that the capacity will eventually get built. Instead, producers are practicing restraint by slowing drilling activity, delaying completions and choking back producing wells to manage their inventory during periods of lower demand and prices. In today’s RBN blog, we consider what this new playbook will mean for pricing trends in the supply basin.
Government forecasts are predicting a sharp drop in natural gas demand in the power sector in the coming decades based on an expectation that the renewable capacity build-out will accelerate and displace other sources. However, forecasts in the past decade have consistently and severely underestimated gas burn for power. In today’s RBN blog, we consider the pitfalls of forecasting gas consumption in a world often focused on pushing a renewables-heavy generation stack.
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.
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.
