You"ve Got Your Troubles - Is The Northeast Gas Market Headed For A Fall Meltdown?
Sunday, 07/26/Published by:Sheetal Nasta
U.S. Northeast natural gas production has surged nearly 1.5 Bcf/d in the past four weeks as wells that were shut-in this spring came back to life. The supply gains have been matched by strong intraregional demand, which has posted at or near record highs on a monthly average basis in recent months. But the returning supply volumes raise the question: what happens when summer cooling demand begins to fade? Storage will only be able to absorb so much, as regional storage inventories are already well above year-ago levels and the historical average for this time of year. That leaves flows out of the region as the only other outlet for excess supply, and those may be limited as well, as pipeline issues and drastically reduced downstream demand from LNG exports have stymied outflows. So, is the Northeast gas market headed for a shoulder-season meltdown? Appalachian gas supply prices this month already have weakened relative to the national benchmark Henry Hub, and these dynamics suggest there is more tumult ahead. Today, we consider what’s in store for the Northeast gas market this fall given the latest fundamentals.
To understand the most recent gas market shifts in the U.S. Northeast — and their near-term implications — it’s worth putting them in the context of what’s transpired in the past few months.
As we discussed last month inThe Waiting Game, gas prices were feeling the pressure of oversupply conditions well before COVID-19 and the oil price collapse. Appalachian producers last year already had trimmed their rig counts and capital spending budgets in response to sub-$2.00/MMBtu gas prices in the region and overall weakness in Henry Hub benchmark futures prices. Then came the mild winter that suppressed storage withdrawals and left a hefty surplus in storage compared with previous years. That was followed by the pandemic-induced stay-at-home directives and lockdowns, which disrupted gas consumption. And, by May, there was also the disruption of another major demand “sink” for domestic production, including from the Marcellus/Utica — U.S. LNG exports — as an existing global surplus of LNG combined with lockdowns abroad to slash global demand, wiping out margins for cargo liftings from U.S. ports, and leading towidespread cargo cancellations.
On top of all that, Appalachian producers have weathered a number of major pipeline outages that cut takeaway capacity for flows out of the region, particularly southbound flows serving Gulf Coast demand, in some cases for prolonged periods of time. Enbridge’s Texas Eastern Transmission (TETCO), for one, has been operating at reduced pressure following a force majeure in early May that triggered federally mandated integrity testing on the system. Outages in already had limited flows on TETCO to below 1.5 Bcf/d (from an average between 1.5 and 2 Bcf/d through ), and this latest incident set flows back further, to less than 1.3 Bcf/d in recent months. Additionally, earlier this year, a force majeure on the Columbia Gas Transmission (CGT) system cut outflows by ~500 MMcf/d for more than a month, from mid-January to early March. Most recently, a July 7 force majeure on Columbia Gas’s Mountaineer Xpress Pipeline (MXP) briefly reduced southbound flows out of Appalachia. (Capacity was restored by July 11 and flows rebounded, but it had forced more gas to flow on other available routes out of the region or into storage.)
The confluence of these dynamics, particularly as the market headed into the low-demand spring “shoulder” season, appeared to be the precursors for a price meltdown. Instead, the region managed to balance without a catastrophic price blowout. The market was left with two adjustment knobs, price or supply and it was supply that was adjusted. Producers decided to shut in wells, which included a 1.4-Bcf/d reduction by EQT Corp. starting May 16. New drilling was already turned back — Appalachian producers had slashed capex in and many of those budgets were reduced further by the first quarter of . As a result of the capex cuts, Northeast gas production through the first four months of the year already was sagging even before the shut-ins took effect, averaging about 31.8 Bcf/d for that period (orange line, left graph in Figure 1), more than 1 Bcf/d below the 32.9 Bcf/d peak monthly average seen in November (blue line, left graph), albeit still 1.4 Bcf/d higher than in January-April . As the shut-ins took effect, volumes fell to an average of about 31 Bcf/d in June, converging with year-ago levels (dashed black oval, left graph). The other side of the market also came through, with near-record regional demand for April, May, and June (orange line, right graph), and by June, absolute demand strengthened enough that the supply-demand balance tightened considerably relative to last year.
Figure 1. Northeast Gas Production and Demand. Source: Genscape
Outflows from the region, a critical component for balancing Northeast supplies, were more of a mixed bag this spring. Figure 2 shows the history by corridor. As the left graph shows, outflows are seasonal: lower during the winter months when more gas is needed to serve heating demand in the north, and higher during the summer and the spring/fall shoulder seasons when there’s less local demand and more gas trying to leave the region. But this year has seen significant limitations on what can leave, both in terms of demand and capacity. After outflows peaked near 16 Bcf/d in October (yellow line, left graph), they fell to around 14 Bcf/d during the winter months and, for the most part, have stayed there. Importantly though, outflows have remained higher than last year. Although flows to the Southeast/Gulf (blue bars, right graph) have been suppressed due to the pipeline outages and lower export demand, outflows have been propped up, albeit just barely, by more supply moving to the Midwest (gray bars, right graph). For more on flow corridors out of the Northeast, seeRoom at the Top Part 2andPart 3.
Figure 2. Northeast Gas Outflows. Source: RBN
In short, between the shut-ins, record cooling demand, and increased flows to the Midwest, the Northeast gas market this spring averted a major meltdown.
Now, of course, the market has continued to demand more gas for summer cooling, so Northeast production has rebounded as shut-in wells appear to have returned (dashed yellow oval in Figure 1). Pipeline flow data shows that total Northeast production receipts hit a high of 32.7 Bcf/d on July 18, and that they have averaged 32.4 Bcf/d since mid-July, up from 31 Bcf/d in June. For now, regional demand in July has remained elevated at record highs, averaging 17.6 Bcf/d, up from about 17 Bcf/d in the same period last year. But that demand typically begins a seasonal decline starting in September as temperatures begin to moderate from summer to fall. If above-normal temperatures should continue, that could prop up regional demand to some degree, as could the overall low gas prices (which would allow utilities to favor gas over coal for powering generation units, although most of that transition has already happened). But at the same time, as temperatures moderate, the influence of temperature anomalies on demand also begins to wane — that is, going from 65 degrees to 75 degrees does not have nearly the impact on power-generation demand as does going from 80 degrees to 90 degrees. Thus, while the region may still see some record-breaking demand for each month, the upside may be limited. And, at an average 32.4 Bcf/d, production would come in ~500 MMcf/d higher than August-September , which means the imbalance between supply and demand is set to worsen considerably in the coming months, beyond just the seasonal effects of the shoulder season.
Then there is storage, which is apt to be much less forgiving than in the spring, as overall storage levels are much higher. We’re now at about the half-way point of the injection season (typically from early April to early November), and according to EIA, the gas storage inventory in the EIA East region is already 72% of the historical maximum fill of 960 Bcf (seen in late October ) and still more than 100 Bcf above last year at this time. Storage last November peaked at 932 Bcf, and the demonstrated maximum peak capacity for the East Region (assuming all storage fields can fill to their individual maximum capacities) is 988 Bcf, also according to EIA. So clearly, the market has to operate to reduce that 100-Bcf surplus before the end of the injection season.
The net impact of all this is that something will have to happen this fall — outflows will need to increase, unforeseen increases in regional demand will have to take place, or the only factor in the control of the producers, production levels, will have to drop through shut-ins, to keep prices from collapsing. But there are possible continuing constraints in outflow capability, limiting that option, whether or not the outbound demand is there. While the CGT issue was resolved and capacity restored, TETCO’s restrictions are expected to continue through mid- to late-October, according to an operations status update posted on the pipeline’s website on July 23. Even if that wasn’t the case, though, that outbound demand may well not be there in the first place as LNG exports remain depressed. Things look a little brighter on that front; Cheniere Energy’s notification deadline for canceling September cargo liftings just passed, and industry reports suggest that cancellations look to be easing somewhat that month. And Cameron LNG was approved last week to begin full operations for Train 3. So, there’s some potential upside to LNG export demand in the coming months. But limited global demand for U.S. LNG is still expected to keep exports well below capacity until winter demand kicks on in Europe to help relieve global oversupply and improve price spreads. There is also always the risk of late-summer or early-fall Gulf hurricanes disrupting demand in the power and industrial sectors to a much greater degree than they affect supply.
As we noted above, Northeast outflows last fall jumped to nearly 15.5 Bcf/d by September and nearly 16 Bcf/d in October (yellow line in Figure 2); that would imply a 1.5- to 2-Bcf/d increase from current levels near 14.2 Bcf/d. But given this year’s supply surplus and the fact that storage is already running 100 Bcf higher than last year, that may not be enough — outflows would likely need to exceed year-ago levels this fall, assuming there is sufficient spare pipeline capacity to do that.
The overall situation and its impact are beginning to show in prices. Spot prices at Appalachian supply benchmark Dominion South already have weakened in July, with basis (price minus Henry Hub) this month to date averaging minus-$0.39/MMBtu (solid orange line in Figure 3), compared with minus-$0.22/MMBtu last month and an average minus-$0.27/MMBtu in July last year (purple line), according to trade data from our friends at Natural Gas Intelligence (NGI). And that is despite the strong summer demand, made stronger by the unusually high temperatures this month. Basis typically weakens during the fall shoulder season. That weakness already is priced into the current forward curve (dashed orange line), and has shifted lower since early July as production rebounded (dashed light and dark gray lines). But this may be just the beginning, considering what it may take to clear fundamental hurdles this fall.
Figure 3. Dominion South Basis. Source: NGI
The bottom line is that if supply continues into shoulder season on its current path, the Northeast gas market appears to be marching toward a price meltdown by September. It would take a combination of multiple factors — incremental demand, increased outflows, and higher injections — to sidestep it. As the imbalance worsens and storage fills, the Northeast will have to discount its gas to flow out on available capacity to other regions, regardless of available demand downstream. If LNG export demand in the Gulf has not rebounded sufficiently by then, the price weakness will then spill over into downstream markets. Worse still, if the Northeast surplus exceeds available storage and outbound capacity, balancing the region would come down to the last resort: more production shut-ins. That is just a healthy market at work, but little solace to producers who lose the cash flow.
"You"ve Got Your Troubles" was written by Roger Greenaway and Roger Cook. It appears as the first song on side one of The Fortunes’ debut album, The Fortunes. Greenaway and Cook said they wrote the song in about two hours. Released as a single in August 1965, the song went to #7 on the Billboard Hot 100 Singles chart. Les Reed, who arranged the song, hired session musicians, with The Fortunes doing the vocals. Reed also arranged the trumpet and horn parts on the record. Noel Walker produced the song. There has been a bevy of other artists who have covered "You"ve Got Your Troubles" over the years. Personnel on the record were: Rod Allen (lead vocals), Glen Dale (backing vocals), Barry Pritchard (backing vocals), supported by unlisted session players.
The Fortunes were an English pop band formed in Birmingham, England, in 1961. Original members in the band were: Rod Allen (lead vocals, bass), Barry Pritchard (backing vocals, lead guitar), Glen Dale (backing vocals, rhythm guitar), Andy Brown (drums), and David Carr (keyboards). Twenty different members have passed through the band since their formation. The Fortunes released 10 studio albums, one live album, and 25 singles. Rod Allen died in , Barry Pritchard in 1999, Glen Dale in , and David Carr in . A four-piece group with no original members still tours as The Fortunes.
