constraints

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. 

After a record run of negative pricing last spring and summer, the Permian Basin collectively cheered as WhiteWater’s Matterhorn Express pipeline began flowing last October, bringing much-needed takeaway capacity to the area. Cash prices at the Waha Hub rebounded and the basin had a relatively uneventful winter, but prices began dropping in early March and have once again traded below zero for most of the past few weeks. This has taken the market somewhat by surprise, as many expected the impact of Matterhorn’s startup to last more than a few months. Prices jumped back above zero on Wednesday and above $1/MMBtu on Thursday, but with major pipeline maintenance coming next week, any relief is likely to be short lived. In today’s RBN blog, we’ll look at what’s driving the recent run of negative pricing in the Permian Basin and what it means until additional infrastructure comes online next year. 

The 1,413-MW Mystic Generating Station, a longtime workhorse for New England, shut its doors for good May 31. Located in Charlestown, MA, on the north side of Boston, Mystic is adjacent to the Everett LNG terminal, which supplied 100% of Mystic’s natural gas for several decades. The power plant’s closure meant the Everett terminal might also be history. However, the Massachusetts Department of Public Utilities (DPU) recently approved new contracts that will keep Everett LNG open for at least six more years. In today’s RBN blog, we’ll discuss the combined impact of Mystic’s demise and Everett’s stay of execution, how the region has handled this summer’s heat wave, and what could be in store for next winter. 

Crude oil output in the Permian Basin is now averaging 6.3 MMb/d, up about 400 Mb/d from year-ago levels and 800 Mb/d from April 2022. The gains — and related increases in associated gas — have spurred a new round of concerns about pipeline exit capacity, complicating drillers’ hopes to boost crude production. In today’s RBN blog, we will discuss the takeaway capacity issue and what it means for producers and pipeline operators, including those planning offshore crude export terminals. 

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.

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 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.

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 race is heating up for building natural gas pipeline takeaway capacity out of the Permian. Associated gas production from the crude-focused basin is at record highs this month and gaining momentum, which means that without additional pipeline capacity, the Permian is headed for serious pipeline constraints — and potentially negative pricing — by late this year or early next, which would, in turn, limit crude oil production growth there. Midstreamers are jockeying for the pole position to move surplus gas from the increasingly constrained basin to LNG export markets along the Gulf Coast. One of the contenders, Matterhorn Express Pipeline (MXP), a joint venture (JV) between WhiteWater, EnLink Midstream Partners, Devon Energy and MPLX, announced its final investment decision (FID) late yesterday. In today’s RBN blog, we provide new details on the greenfield project.

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.