Dominion South

Outbound natural gas flows from Appalachia over the weekend hit a new record high of 17.3 Bcf/d and averaged 16.7 Bcf/d for April — an all-time high for any month. That’s despite pipeline maintenance season being well underway last month and intermittently curtailing production and outflow capacity. Utilization rates of takeaway pipelines from the region are soaring above 90%, with little more than 1 Bcf/d of spare exit capacity for outflows of surplus Northeast production. Whether that will be enough to stave off severe constraints and discounted pricing in Appalachia in what’s left of the spring season, and again in the fall will depend on how much surplus gas is left after meeting in-region consumption and storage refill requirements. What happens when seasonal demand declines occur in May and June? In today’s blog, we wrap up our analysis of current outbound capacity utilization and where that leaves the Northeast gas market this spring.

This time last year, Appalachian natural gas production was approaching a steep springtime ledge as regional prices sank below economic levels and producers responded with real-time shut-ins. This year to date, regional gas prices have averaged $0.80-$0.90/MMBtu above 2020 levels for the same period, and production has been averaging more than 1 Bcf/d above year-ago levels. If production holds steady near current levels, the year-on-year gains would just about double to ~2 Bcf/d by mid-May, which is when the bulk of the springtime curtailments first took effect in 2020. This, just as Northeast demand takes its seasonal spring plunge, which means regional outflows are poised to rise in the coming weeks, potentially to record levels. How much more can the Appalachian takeaway pipelines absorb? In today’s blog, we continue our analysis of outbound capacity utilization, this time focusing on the routes to the Midwest.

Natural gas pipeline takeaway constraints out of the Northeast worsened in 2020 despite producer cutbacks in the region as high storage levels and weaker demand led to record volumes of Appalachian gas supplies needing to find outlets in other regions last fall. This year, storage levels are lower and could absorb more of the surpluses during injection season. However, Appalachian gas production so far in 2021 has been averaging higher than last year; and, gas prices are higher year-on-year, reducing prospects for the kinds of producer curtailments we saw last year. As for the “pull” from downstream demand, LNG exports along the Gulf Coast aren’t expected to experience the slump from cargo cancellations seen last summer. In other words, Appalachia’s outbound flows are likely to be robust, setting the stage for takeaway constraints and weak prices, particularly during the spring and fall shoulder seasons. How much outbound capacity currently exists and how much room is there for growth? Today, we continue our series on the Northeast gas market with an update on Appalachia’s southbound takeaway capacity and outflows, starting with a detailed look at the gas moving to the Southeast and to the Gulf Coast.

Last year served as something of a bellwether for what’s to come for the Northeast gas market in the long term: increasing takeaway pipeline constraints and weakening gas price differentials by mid-decade. The region’s outflows surged to record highs in the fall of 2020 as production also reached fresh highs. Just a couple weeks ago, the region notched another milestone on the pipeline constraint yardstick: record outflows on some pipes and near-full utilization of southbound routes on the coldest days of winter — something we don’t normally see, as gas supply requirements in the Northeast peak with heating demand and less gas is available to flow out of the region. This time, the surge in outflows and the resulting constraints were driven more by spiking demand and gas prices downstream than by oversupply conditions at home, but the result was the same: the Northeast had by far the lowest prices in the country. This happened even as other regions recorded triple-digit, all-time high prices. Today, we examine how Appalachia outflows and takeaway capacity utilization shaped up during Winter Storm Uri.

Despite Northeast natural gas producers battling stiff headwinds last year — the lower rig count, sub-$1.50/MMBtu spot prices, lower demand, and price-responsive shut-ins in the shoulder periods — Northeast gas production volumes still managed to hit record highs in 2020, both for daily output as well as on an annual average basis. Regional production flows averaged 32 Bcf/d in 2020, up from 31.3 Bcf/d in 2019, and daily pipeline flow data shows volumes sustained year-on-year gains through January 2021. Today, we continue our series on the Northeast gas market fundamentals, this time with a sharper focus on production trends.

After a two-year reprieve from a nearly decade-long period of severe pipeline constraints and debilitating prices, Northeast natural gas producers are again headed for a constraint-driven market in the next five years. Appalachian supply prices last year weakened relative to national benchmark Henry Hub, reversing the gains of the past few years, and fell to historic lows as oversupply conditions prevailed and at times strained available takeaway capacity. All that despite the rig count hitting a four-year low and shale producers’ best — even unprecedented — efforts to respond to low prices with short-term production cutbacks during the shoulder seasons. So what happens when rig counts and production recover in the coming years? How long before pipeline constraints worsen and what are the prospects for new pipeline development? Today, we begin a blog series detailing recent supply-demand trends in the region and our outlook for 2021 and beyond.

As U.S. natural gas spot and futures prices retreated in the past week, the price of gas at Appalachia’s Dominion South hub fell as low as $0.735/MMBtu, the lowest since fall 2017, before partially rebounding yesterday to about $1.10/MMBtu, according to the NGI daily gas price index. Moreover, the forwards market indicates sub-$1/MMBtu prices are in store for October as well. The regional supply hub didn’t weaken quite as much as prices at the national benchmark Henry Hub, which collapsed in recent days on demand losses — from cooler weather, storm-related power outages, and disruptions to LNG exports — and storage levels in the Gulf Coast region that are well above average and approaching peak capacity levels. The relative support for prices in the Northeast is in part due to a second round of production shut-ins by EQT Corp., which took effect September 1. But seasonal demand declines are underway; the Dominion Energy Cove Point LNG facility in Maryland just went offline for its annual fall maintenance, placing additional pressure on already-packed storage fields and takeaway pipelines; and pipeline maintenance events are reducing outflow capacity and curtailing production. Altogether, that signals more volatility ahead. Today, we provide an update on the fundamentals driving the Northeast gas market.

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.

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.

The U.S. Northeast natural gas market has had a volatile few weeks. Regional gas production has surged, averaging 30.4 Bcf/d in the second half of October (2018), up 800 MMcf/d from the first half of the month and up nearly 1 Bcf/d from the September average. Normally (for the past several years), those kinds of supply gains, particularly in a shoulder month and during maintenance season, would have one result: Marcellus/Utica prices taking a nosedive. But that’s not exactly the case this year. Instead, Appalachian spot prices have been on a wild ride the past few weeks, swinging from barely $1.00/MMBtu (or more than $2.00/MMBtu below Henry Hub) on October 8, to over $3.00 (just $0.12 under Henry) on October 24 — the highest levels seen at this time of year since 2013, both in terms of outright prices and basis differentials to Henry Hub. The catalyst is nearly 3 Bcf/d of new takeaway capacity from the growing producing region that has been added in recent weeks, including, most recently, partial service on a brand-new route on Enbridge/DTE Energy’s 1.5-Bcf/d NEXUS Gas Transmission. What does this latest round of expansions and the resulting basis strength mean for the Northeast and its downstream gas markets? In today’s blog, we discuss highlights from our new 26-page report on evolving Northeast gas takeaway capacity utilization and additions, and their effects on price relationships.