Posts from Sheetal Nasta

Monday, 01/30/2023

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.

Tuesday, 01/17/2023

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.

Sunday, 01/08/2023

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.

Tuesday, 12/20/2022

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.

Tuesday, 12/13/2022

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.

Monday, 11/28/2022

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.

Wednesday, 11/16/2022

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.

Sunday, 11/06/2022

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.

Wednesday, 10/19/2022

Permian crude oil production has climbed ~30% since the lows of 2020 to about 5.2 MMb/d this summer and helped keep crude oil — and gasoline — prices in check as market balances tightened. With that has come a lot of gross gas, which surged by over 40% to 21.3 Bcf/d on average this summer, up from the 2020 low of just under 15 Bcf/d. If unconstrained by infrastructure, RBN expects that to grow another 30%, or more than 6 Bcf/d, in the next three years, but only if there is adequate midstream capacity — everything from gathering lines to processing plants and, ultimately, gas and liquids transportation lines to deliver the products to consuming markets on the Gulf Coast. While there’s been a significant midstream build-out over the past two years, and more expansions are in the works, there are major outstanding questions about whether it will get built in time and in the right places to prevent prolonged bottlenecks.  In today’s RBN blog, we continue our series focusing this time on upcoming expansions and how total processing capacity stacks up against RBN’s Mid-Case production outlook over the next several years.

Monday, 10/10/2022

When it comes to U.S. crude oil plays, no basin has been more resilient than the Permian post-2020, and by extension, no basin has played a bigger role in taming oil prices — and regional natural gas prices — in recent months. While crude production in most other oil-focused basins is flat-to-lower on average since 2020, Permian crude output has climbed 15% in that time, from about 4.5 MMb/d in 2020 to just over 5.1 MMb/d this year to date, with much of that growth occurring in the past year or so. You could say Permian crude saved the day — at least for a time. However, that growth could not have happened without a significant build-out of natural gas midstream infrastructure. And a lot more of it will be needed if Permian crude production is to continue growing and keep U.S. crude oil prices in check. In today’s RBN blog, we provide an update on gas processing capacity in the Permian.

Sunday, 09/25/2022

The battle to restore energy reliability in Europe has breathed new life into North American LNG export projects — and into the Haynesville Shale in Louisiana, the closest supply basin to many of the planned and proposed liquefaction facilities. Gas production in the region has climbed more than 4 Bcf/d — an impressive 39% — since 2019 and we expect it to grow nearly as much over the next three years. The big question on everyone’s mind, however, is whether there will be enough pipeline capacity to move that gas to where it’s needed on the coast. Pipeline capacity for southbound flows through the Bayou State is already showing signs of stress. Will recently completed and upcoming debottlenecking projects help stave off major supply and pricing disruptions? In today’s RBN blog, we provide our outlook on Haynesville production and the nature and timing of Gulf-bound pipeline projects.

Sunday, 09/18/2022

Lower 48 natural gas production this month hit a once-unthinkable milestone, topping the all-important psychological threshold of 100 Bcf/d for the first time. Volumes have remained at record highs through mid-September, with year-on-year gains expanding to a breathtaking 7-9 Bcf/d above last year at this time (when hurricane-related shut-ins were in effect). The record production levels coincided with a seasonal decline in weather-related demand, as well as the ongoing outage at the Freeport LNG export terminal. Remarkably, however, even with all-time high, ~100 Bcf/d natural gas production and Freeport LNG offline, the Lower 48 gas market balance averaged tighter year-on-year — a testament to just how strong consumption has been lately, and for much of this summer for that matter. In today’s blog, we look at how the supply-demand balance has shaped up this month and where it’s headed near-term.

Monday, 09/12/2022

The U.S. natural gas market is one of the most transparent, liquid and efficient commodity markets in the world. Physical trading is anchored by hundreds of thousands of miles of gathering, transmission and distribution pipelines, and well over 100 distinct trading locations across North America. The dynamic physical market is matched by the equally vigorous CME/NYMEX Henry Hub natural gas futures market. Then, there are the forward basis markets — futures contracts for regional physical gas hubs. These pricing mechanisms play related but distinct roles in the U.S. gas market, based on when and how they are traded, their respective settlement or delivery periods, and how they are used by market participants. In today’s RBN blog, we continue a series on natural gas pricing mechanisms, this time with a focus on the futures and forwards markets.

Sunday, 08/28/2022

The 2022 hurricane season is off to a quiet start, but the tropics seem to have awakened in recent days and are likely to ramp up in September — the peak month for tropical storm activity. Forecasters are still predicting an above-average season, calling for as many as 10 hurricanes and up to five major ones. That would mean greater volatility for energy markets in any year, but the stakes are arguably higher this year than any time in recent memory — especially for natural gas. That’s because prices are already at the highest level in over a decade and flirting with the $10/MMBtu mark. The gas market is tight domestically and globally, particularly in Europe. Lower 48 storage remains near the five-year low. European gas storage, after lagging far behind, has caught up to the five-year average this month, but the continent is still dependent on a consistent stream of U.S. LNG cargoes, particularly as it works to wean itself off Russian gas supplies. What happens when you add to that the prospect of hurricane-related disruptions to Lower 48 production or LNG exports, or both? Much of that will come down to the timing, path and strength of any impending storms. That’s a lot of unknowns, and where there is that much uncertainty, volatility is sure to follow. With the National Hurricane Center (NHC) predicting high chances of potential cyclone development as early as later this week, today’s RBN blog considers the possible implications for the U.S. gas market balance.

Monday, 08/01/2022

Just downstream from the Appalachian supply basin — where daily spot natural gas prices are among the lowest in the country — cash and forward prices in the Mid-Atlantic and Southeast have rocketed, becoming the highest gas prices in the land, and in some cases are at never-before-seen levels for this time of year. No doubt it’s been a sweltering summer so far, and low storage levels aren’t helping either. But there’s more to the price premiums than that. Limited access to supply and constraints on Williams’ Transco Pipeline — the primary system delivering gas to the region — have created a demand “island” there just as persistent heatwaves boosted cooling demand. Moreover, without additional pipeline capacity, the dynamics unfolding this summer could become a regular feature of the Southeast/Mid-Atlantic markets. In today’s RBN blog, we break down the factors driving regional prices to new heights.