You've Got Your Troubles, Part 2

The Northeast natural gas market this past spring and early summer averted a major meltdown, as production shut-ins, record cooling demand, and increased outflows helped the region balance. But the fall shoulder season is liable to be less forgiving, given that storage levels are much higher and carrying a surplus to prior years. Now, shut-in wells are back online for the most part and production has surged. In-region demand has been at record highs, but summer cooling demand will peak soon and give way to balmy fall weather. As that happens, the Northeast will increasingly rely on outbound flows to offset a growing supply imbalance. But pipeline capacity utilization for routes moving gas out of the region have been running high already. How much incremental volumes can the takeaway pipelines absorb before constraints develop and hammer regional supply prices? Today, we analyze flows and capacity out of the region.

We’ve looked at Marcellus/Utica gas pipeline takeaway capacity in-depth before in blogs like the Room at the Top series and before that the Dog Days Are Over series. In past years, our discussion of takeaway capacity was in the context of a market that was severely oversupplied and constrained year-round and largely at the mercy of pipeline projects to increase capacity out of the region. By late 2018, however, the bulk of the pipeline expansions were completed and online; after years of being reined in, the Northeast finally had sufficient, even excess, takeaway capacity and was largely relieved of constraints. But as we saw in fall 2019 — and wrote about in Punching Bag — the Appalachian supply region is not entirely free and clear; it remains susceptible to congestion and takeaway constraints during low-demand “shoulder” periods in the spring and fall when there is a greater surplus of gas volumes needing to leave the area.

This fall, the situation could be even worse and may force producers to shut-in gas for a second time this year. As we discussed in detail last week in Part 1, producer shut-ins starting in May and record cooling demand have helped tighten the Northeast region’s supply-demand balance and prop up prices relative to the national benchmark Henry Hub. But shut-in wells were brought back online last month, and pipeline flow data from our good friends at Genscape shows that local production surged to an average 32.5 Bcf/d in the second half of July, up 1 Bcf/d from the first half of the month. That, combined with the reality that storage levels are high and carrying surpluses to prior years, is setting up the region for major constraints as local demand experiences seasonal declines this fall. The fundamentals imply that record amounts of gas may need to flow out of the Northeast in order to balance the region. To make that happen, Marcellus/Utica gas would have to price itself to move as much as possible out of the region, regardless of whether there is sufficient demand downstream. Because if that’s not enough either, producers would need to resort to shutting in wells again. (EQT Corp., which led the Northeast production shut-ins this spring and early summer, indicated in its earnings call last week that while it is well-hedged, another round of shut-ins is not out of the question for late summer and fall if economics worsen.)

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In other words, outbound flows and capacity will once again be the primary driver of the Northeast market this fall. So, next, we take a closer look at capacity and utilization of the pipeline corridors leaving the region to understand how much more can leave the region before constraints develop.

We start with a quick recap of the pipeline routes and capacities for supply leaving the Northeast, now totaling nearly 17.5 Bcf/d. Of that, about 10.4 Bcf/d of capacity is designed to move Marcellus/Utica gas to the Gulf and Southeast/Atlantic states, nearly 90% of it via legacy long-haul pipelines that once moved gas supplies north from the Gulf Coast producing regions but were reversed to flow north to south. These include the “T pipes” (because their names happen to start with the letter “T”): Williams’s Transco, Kinder Morgan’s Tennessee Gas Pipeline (TGP), Boardwalk Pipeline Partners’ Texas Gas Transmission (TGT) and Texas Eastern Transmission’s (TETCO) easterly leg (a.k.a. the “30-inch” line), as well as another legacy pipe: TC Energy’s Columbia Gulf Pipeline. This corridor also includes the portion of Energy Transfer’s Rover Pipeline and Tallgrass Energy’s Rockies Express Pipeline (REX), which primarily move gas to the Midwest but also deliver gas indirectly to the Gulf Coast via deliveries into third-party pipelines.

The other 7.1 Bcf/d of outbound capacity moves Appalachian gas volumes to the Midwest/Midcontinent — as well as to Canada. This corridor comprises two large-diameter, greenfield pipes: DTE Energy and Enbridge’s NEXUS and Energy Transfer’s Rover Pipeline; as well as Rockies Express Pipeline (REX), following the reversal and expansion of its eastern segment, and TETCO’s westerly leg, known as the “24-inch” line. There are also two export pipelines that deliver into Canada: TGP and National Fuel’s Empire Pipeline.

Next, we detail recent flows and utilization on these routes and what that will mean for available exit capacity this fall. As we noted in the previous blog in this series, outbound flows out of the Northeast 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. 

Southeast/Gulf Corridor

Southbound corridor flows out of the Northeast started strong in early 2020, as higher production and a mild winter meant that outflows remained relatively elevated through winter. Outflows averaged 7.8 Bcf/d in the first quarter, up 2.3 Bf/d year-on-year (dark green lines, Figure 1). But in contrast to last year, volumes have been flat to lower through the spring and summer months. While April outflows were above year-ago levels, outbound volumes fell back a bit to 7.5-7.6 Bcf/d in May and June to average 7.7 Bcf/d for the second quarter, nearly unchanged year-on-year (brown lines). And in July this year, those flows have stayed relatively flat to previous months at 7.5 Bcf/d, which is 200 MMcf/d lower than in July 2019 (compare red lines). The relatively weaker southbound flows can be attributed to reduced takeaway capacity, with TETCO still operating at a reduced pressure and CGT also experiencing a major, albeit short-term outage in July, and downstream LNG export demand being cut by more than half. Production shut-ins in the Marcellus/Utica from mid-May to mid-July in response to low gas prices tightened the region’s supply-demand balance and also kept outflows in check.

Figure 1. Northeast Gas Outflows to Southeast/Gulf. Source: RBN

The fact that somewhat less gas supply needed to leave the region is a good thing, considering that operational capacity for southbound flows has been running lower than last year. The corridor’s capacity would normally be 10.4 Bcf/d (black line). But as we also noted in Part 1, capacity was reduced to more like an average 9.8 Bcf/d last fall, following an incident on the TETCO 30-inch line. That same event also triggered an extended period of integrity testing that has required the line to operate at a reduced pressure ever since then, bringing operational capacity down closer to 9 Bcf/d in recent months (gray line in the graph). In early July, a force majeure on CGT further curtailed outbound capacity, but that capacity was restored by mid-month. Given the reduced capacity, utilization on the southbound corridor has been especially high this spring/summer to date, averaging near the 85% level and topping 90% many times, compared with about 75% last year, despite lower outflow volumes than last year.

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Midwest/Canada Corridor

With the Southeast/Gulf corridor capacity restricted and demand constraints downstream, somewhat more gas has flowed to the Midwest than in 2019 (Figure 2). Aggregated flows on these routes have been relatively more range-bound at the 6- to 7-Bcf/d level since early 2019. Westbound flows started 2020 higher year-on-year, averaging 6.6 Bcf/d through the first quarter, up 700 MMcf/d from the same period last year (blue average lines on the graph). And, unlike southbound flows, they’ve remained higher through much of spring and summer to date, at 6.7 Bcf/d, with the exception of some dips during cold snaps in April. That level is an average ~600 MMcf/d above year-ago levels (orange lines). With capacity at about 7.1 Bcf/d, that put utilization at over 95% through that period. In July alone, outbound flows via this corridor have accelerated to an average 6.83 Bcf/d, up 800 MMcf/d year-on-year (purple lines).

Figure 2. Northeast Gas Outflows to Midwest/Canada. Source: RBN

Total Northeast Outflows

Combined, the two outbound corridors flowed an average ~14.4 Bcf/d out of the region in the past three months, nearly 500 MMcf/d more than last year (orange line, Figure 3). Total operational capacity (again, after accounting for the capacity reductions on TETCO and, briefly, CGT) during that period averaged 16.3 Bcf/d, implying an 88% utilization rate, compared with 79% a year ago. In the second half of July, in particular, as shut-in wells came back online and production rose by ~1 Bcf/d, outflows increased — albeit modestly, given that demand was also higher — to an average 14.6 Bcf/d. Pipeline utilization rates dropped slightly, as CGT capacity was restored and capacity ticked up to about 16.5 Bcf/d. Nevertheless, it’s safe to say that utilization rates have been running high, and they would already be even higher than this, if not for the production shut-ins, hotter-than-normal weather, and the resulting record demand that we’ve seen in the Northeast over the past few months.

Figure 3. Total Northeast Gas Outflows. Source: RBN

That doesn’t bode well for spare exit capacity this fall and the region’s ability to rely on incremental outbound flows to balance the surplus production and storage in the region. We know that Northeast’s gas surpluses tend to run higher during fall shoulder season than during the summer, so outflows likely will need to rise heading into September. It’s also likely that outflows will need to rise to levels higher than they did last year, given current production and storage levels. But there appears to be little wiggle room when it comes to outflows.

Outbound flows last September and October averaged 15.3 Bcf/d and 15.7 Bcf/d, respectively, or about 92% of the total capacity of 16.9 Bcf/d at the time. Current outbound capacity, as we noted above, is lower than that at 16.5 Bcf/d (again, accounting for the TETCO capacity reductions), and there’s little upside to that between now and September as TETCO expects its pressure restrictions to extend through mid- to late-October. The only other incremental capacity this year comes from Empire Pipeline in the Midwest/Canada corridor. The pipeline on July 11 began partial in-service of its 205-MMcf/d Empire North expansion project, bringing online an incremental 85 MMcf/d of capacity for delivering into Canada; it’s expecting to bring on the remaining 120 MMcf/d by October 1. (Flows don’t indicate an uptick in response to the new capacity, but that could change in August as shippers nominate for the new month.)

For now, if we assume an operational capacity of 16.5 Bcf/d (or even 16.6 Bcf/d, including the recent 85-MMcf/d addition on Empire) across all takeaway routes for September/October, and if we assume that outflows will rise to at least year-ago levels for that time of year, that leaves just 0.9–1.3 Bcf/d of spare exit capacity to manage surpluses above and beyond what flowed last year. That may sound like plenty, but it’s not when you consider that the current level of production (~32.5 Bcf/d) is about 1 Bcf/d higher than this time last year and 600 MMcf/d above September 2019 levels. You also need to factor in that storage levels are much higher than they were this time last year and also will have less capacity to absorb excess gas supplies.

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"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), and 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 2008, Barry Pritchard in 1999, Glen Dale in 2019, and David Carr in 2011. A four-piece group with no original members still tours as The Fortunes.