Basis

What happens when almost everybody is on the same side of a trade and the fundamentals flip? Yup, max pain. Everyone races for the exits at the same time, sending the market into speculative liquidation mode and causing cascading losses. It can get frantic and ugly — tens or even hundreds of millions of dollars are at stake, and no one’s sure how bad things might get. As we discuss in today’s RBN blog, frantic and ugly is precisely what happened over the last few days at the Waha natural gas trading hub in West Texas. 

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.

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.

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.

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 primary 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 take a closer look at the primary pricing mechanisms driving the U.S. gas market.

If you’re going to be involved in any aspect of U.S. natural gas, it’s critically important to understand how physical, futures, and forward gas markets work and how pricing is determined. That reality was emphasized almost exactly a year ago when physical spot prices for U.S. natural gas had their most volatile and bizarre weeks ever as Winter Storm Uri sent a blast of bitter-cold, icy weather down the middle of the country, wreaking havoc on gas infrastructure just when heating demand was at its highest. Prices in the Northeast, which normally see winter spikes, barely reacted, while prices across the Midcontinent and Texas rocketed to record-shattering levels, above $1,000/MMBtu. The events of the Deep Freeze of February 2021 have since brought renewed scrutiny to the various aspects of the gas and power markets, and a need among legislators, regulators and everyone who deals with energy commodity markets to understand how gas is traded in the U.S. and how prices are set. We’re here to help. So, in today’s RBN blog, we begin a deep dive into the process, quirks and idiosyncrasies of U.S. gas pricing.

There was no shortage of drama in the U.S. natural gas market last week. The February Henry Hub CME/NYMEX contract expired in a blaze of glory after frenzied short-covering led to the largest single-day percentage gain since Henry futures began trading in the 1990s. The Northeast was bracing for a weekend “bomb cyclone,” a particularly gnarly nor’easter that brought frigid temperatures and threatened to disrupt the market just as heating demand spiked. But there was another, more subtle but still seismic event that occurred, one that is likely to reverberate well beyond the near-term horizon. Namely, the Equitrans Midstream-led, 2-Bcf/d Mountain Valley Pipeline — the only major expansion project left for increasing egress out of the Appalachian gas supply basin — lost two key federal permits, all but ensuring that the long-delayed project will miss its latest target in-service date of this summer, and potentially be held back another year, or more. In our Top 10 Prognostications for 2022 blog, #7 predicted more severe capacity constraints and weaker basis differentials for Appalachian gas producers. This is the latest indication that things could get worse — and sooner — than previously expected. In today’s RBN blog, we focus on our latest outlook for Appalachia’s gas takeaway constraints and basis pricing.

Market signals are suggesting that we’re on the cusp of another midstream revival. Higher crude oil and natural gas prices are prompting producers to ramp up output, and higher production will lead to increasing midstream constraints and cratering supply prices. We’ve seen this reel before and in past cycles, midstreamers would swoop in right about now with plans for a host of pipeline expansions to relieve bottlenecks and balance the market again. The problem is that for capacity to get built, you need producers to sign up with long-term commitments, and that’s the catch. Wall Street has drawn a hard line when it comes to capital and environmental discipline in the energy industry, and regulatory support for hydrocarbon newbuilds has waned. This is especially a problem for two major basins — the Permian and Marcellus/Utica — but is liable to affect producer behavior across the Lower 48. In today’s RBN blog, we take a closer look at how this will play out at the basin level, starting with the Permian.

With natural gas prices reaching levels not seen in seven years, Western Canada is doing all it can to help increase gas supply, with recent data showing monthly production hitting multi-year highs. Moreover, Canadian forward gas prices are at the highest levels since 2014, gas pipeline expansions are in place or being constructed to accommodate future supply expansion, and gas-focused drilling activity remains strong — all of which may as well be a prescription for sending gas production to record levels later this year and in 2022. In today’s RBN blog, we provide an update on the recent gas production growth in Alberta and neighboring provinces and why more growth is coming.