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.
Posts from Sheetal Nasta
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.
If pipeline-constrained Haynesville Shale producers’ New Year’s resolution was to grow volumes, they just got a big boost: Energy Transfer recently placed in service its new Gulf Run Transmission natural gas pipeline in Louisiana, increasing north-to-south capacity in the state by 1.65 Bcf/d. It’s the first of several pipeline projects due online in 2023 — and among others proposed for subsequent years — that will be critical for debottlenecking the Louisiana pipeline network and connecting Haynesville and other gas production volumes to LNG export projects vying for feedgas supply on the Louisiana coast. U.S. LNG developers are in a race to capitalize on the tight global LNG market and finalize terminal plans, with much of the next wave of liquefaction and export capacity additions planned for the Louisiana coast which may, in time, help alleviate energy security concerns, particularly across the pond in Europe. If these pipeline projects don’t get built on time, the resulting supply shortage in southern Louisiana would not only wreak havoc on Henry Hub and the domestic gas market but would reverberate around the globe. Gulf Run’s in-service is good news for at least one facility: the under-construction Golden Pass LNG, which is the anchor shipper on the pipeline and due to begin commissioning later this year. In today’s blog, we look at what the new capacity could mean for flows and production growth in the short- and long-term.
Tallgrass Energy last month snagged an early Christmas present: It won a bid for Ruby Pipeline, the beleaguered Rockies-to-West Coast natural gas system that has long been underutilized and cash-poor. In doing so, it beat out one of the largest midstream companies in North America and a long-time co-owner of Ruby — Kinder Morgan. Ruby may be a languishing asset, but for Tallgrass it’s more like a crown jewel in its quest to be the only transcontinental header system in the country that would connect trapped Appalachian gas supply with premium West Coast markets. Tallgrass’s Rockies Express (REX) pipeline is already moving Marcellus/Utica molecules west to the Rockies — the opposite direction than it was originally built for in the pre-Shale Era. The Ruby acquisition, which has yet to close, would allow Tallgrass to extend its reach farther west, directly into the premium West Coast markets. The Ruby deal comes at a time when California’s aggressive decarbonization goals are leading to gas shortages and exorbitant fuel premiums out west, and there’s an immediate need to debottleneck routes to get gas there. In today’s RBN blog, we begin a series delving into how Ruby fits into the Western U.S. gas market and what the acquisition would mean for Tallgrass.
As U.S. LNG export project development accelerates along the Gulf Coast, one of the big uncertainties is where will all that feedgas come from? We estimate that there are a dozen Gulf Coast projects totaling 16 Bcf/d of export capacity in the running for completion in the next decade, with 60% of that capacity sited along a less-than-100-mile stretch of coastline straddling the Texas-Louisiana border. One of the major factors that will influence the timing and commercialization of the projects is the availability of feedgas supply where and when it is needed. With pipeline projects and production growth in the Marcellus/Utica shales at a veritable standstill, the Texas and Louisiana production regions — the Permian, Eagle Ford and Haynesville — are the frontrunners for serving the bulk of the resulting Gulf Coast demand growth. Assuming no midstream constraints, RBN’s Mid-case production forecast anticipates growth from the three basins will total 15.5 Bcf/d by 2032. In today’s RBN blog, we look at how well (or not) production levels will line up with feedgas demand.
Last week, even as natural gas day-ahead prices went negative in the Permian’s Waha Hub in West Texas, spot prices at northern California’s PG&E Citygate last week traded at a record-smashing $55/MMBtu, according to the NGI Daily Gas Price Index — close to 100x the Waha price. Other hubs west of the Continental Divide also surged to record levels, while markets just east and north of there were largely unruffled — a sure sign of bottlenecks for moving gas into West Coast markets. This is just the latest instance of severe gas supply shortages and constraint-driven price disruptions out West in recent years (even ignoring Winter Storm Uri and the Deep Freeze of February 2021). Moreover, it’s arguably taking progressively more benign market events to trigger similar or worse shortages. What’s going on? In today’s RBN blog, we break down the factors driving the latest Western U.S. gas price spikes.
The first wave of Gulf Coast liquefaction and LNG export facilities was well-timed, coming as it did with fast-rising natural gas supplies in the Lower 48 and a slew of pipeline reversals and expansions that enabled billions of cubic feet a day of low-cost Marcellus-Utica gas supplies to reach Gulf Coast markets. Permian and Haynesville supplies helped too. The next wave of LNG development, which will kick off in earnest in 2024, may not go quite as smoothly, however. Global demand for LNG is there — there’s little doubt about that. But the next phase of export capacity growth may well be hemmed in by domestic factors, namely the timing and availability of gas supplies to the Gulf Coast due to potentially serious midstream constraints. In today’s RBN blog, we look at where the feedgas supply is likely to come from and what that will mean for pricing dynamics.
The energy landscape in Texas has undergone significant changes in the two years since the calamitous events of Winter Storm Uri in February 2021. The extreme weather wreaked havoc on the state’s electric generation and natural gas systems, and subsequent investigations resulted in two reform bills — Senate Bill 2 and Senate Bill 3 — aimed at installing new leadership at the Electric Reliability Council of Texas (ERCOT), the electric grid operator, and requiring state regulators to develop rules and standards to address the points of failure in electricity and natural gas infrastructure and operations. Since the bills were signed into law in June 2021, oil-and-gas, electric-grid and utility monitors have adopted a number of requirements, some more prescriptive than others. In today’s RBN blog, we highlight what has changed and where there are still potential gaps.
The crude-oil-driven Permian has been a hotbed of midstream development in recent years and that’s unlikely to change anytime soon. RBN estimates Permian gross gas production surpassed 22 Bcf/d last month and projects that, if unconstrained by infrastructure, it would grow by another 4 Bcf/d or so over the next couple of years. One determinant of that rate of growth is adequate capacity to process gross gas volumes. In today’s RBN blog, we conclude this series with an assessment of the timing of processing capacity additions in the basin vs. RBN’s Mid-case gross gas production forecast.
