The Northeast natural gas market was supposed to have turned a new leaf. After years of pipeline takeaway constraints and constraint-driven prices, the region as of late 2018 had ample, even excess, takeaway capacity on its hands. Regional prices strengthened on both an absolute basis and relative to downstream markets, and Marcellus/Utica producers had room to grow. But bearish fundamentals have rattled the Northeast — and U.S. — market in recent months. In-region demand has lagged, even as production has set new highs. Since August, capacity reductions on Texas Eastern Transmission, a key Northeast takeaway route, have limited outflows. And, to top it off, Dominion’s Cove Point LNG went offline last month for an annual three-week-long maintenance, taking another 700 MMcf/d of demand out of the market for a time — it has since come back online, as of this past Monday. But regional prices in late September and early October were pummeled in the process, raising the question: are the Northeast’s takeaway constraints back? Today, we analyze the impacts of shoulder-season dynamics on regional storage and takeaway capacity utilization.

Despite pipeline takeaway constraints being relieved this year, Northeast natural gas prices have averaged lower than last year through much of the injection season. They’ve been especially weak in recent weeks, with spot prices at Appalachia’s Dominion South hub averaging $1.27/MMBtu in October to date, which is about half of where they stood this time in 2018 and the lowest in two years. And earlier this month, on October 4, regional prices went into apocalyptic territory, plunging 30-50% to less than $1/MMBtu — reminiscent of the deep discounts of recent years when Marcellus/Utica producers were operating under severe pipeline constraints. Prices rebounded the very next trading day, but they remain depressed relative to last year. Today, we look at the fundamentals behind the recent price weakness. Starting today, you can also tune into an audio version of the current day’s blog. Click here to find out how to subscribe or start listening by clicking on the play button above.

New fractionation plants, steam crackers and export facilities are being built along the Gulf Coast, all spurred by rising U.S. production of natural gas liquids. This incremental NGL output and these new projects are putting serious pressure on existing NGL pipeline and storage infrastructure, and prodding the development of new salt-cavern storage capacity for mixed NGLs, NGL purity products, and ethylene and other olefins. Also, new, expanded and repurposed pipelines to enhance NGL-related flows throughout the region are in the works. Today, we continue our series on NGL storage facilities along the Gulf Coast with a look at Easton Energy Services’ plans for more underground storage capacity in Markham, TX, and new NGL and olefin pipelines.

With another month of anemic storage injections in September, Alberta natural gas storage levels remain on track to start the next heating season at a 13-year low. Still, while Alberta gas storage has been lagging well behind in terms of average injection rates and storage levels for many months now, forward winter contract prices for the Western Canadian gas price benchmark of AECO have budged only a little. There is potential for an improvement in storage injection rates during October after a recent regulatory approval affecting the Alberta gas pipeline system, but there is little time remaining in the current injection season to make much of a difference in inventory levels going into winter. Today, we conclude this two-part series with a look at why the AECO forward market remains largely unconcerned with low Alberta gas storage levels.

The Permian Basin’s crude oil market over the last 18 months has exhibited so many dynamic changes that dedicated observers may be suffering from a bit of neck strain, if not outright whiplash. We’ve seen production rise at an unprecedented rate, followed by a period of slower growth. We’ve also watched the Permian very quickly transform from a region desperate for new long-haul pipeline capacity to a hotbed for midstream investment and infrastructure growth. While we’ve closely tracked these big-picture changes, a lot of other, smaller-scale knock-on effects have been occurring too, with potentially significant implications for the basin’s supply pricing and transportation economics. Today, we explain why the changing fortunes of Permian crude haulers may benefit producers in the basin.

During the 2010s, the Marcellus/Utica region has experienced an astonishing 16-fold increase in natural gas production, from 2 Bcf/d in early 2010 to more than 32 Bcf/d today. The region’s rapid transformation from minor energy player to superstar came with a lot of infrastructure-related growing pains, many of them tied to the urgent need for more gas pipeline takeaway capacity. Takeaway constraints have largely been addressed — at least for now — but producers’ continuing efforts to develop “wet,” liquids-rich parts of the Marcellus/Utica have resulted in an ongoing requirement for more gas processing and fractionation capacity. Put simply, as wet-gas production ramps up, so must the region’s ability to process that gas and its associated natural gas liquids. Today, we continue a series on existing and planned gas processing and fractionation projects in the Northeast with a look at the growing role played by Williams and its new Canadian partner.

After months of severe natural gas pipeline constraints, Permian producers and shippers are reveling in the relief of new takeaway capacity. Kinder Morgan’s Gulf Coast Express (GCX) Pipeline, which began flowing initial volumes in mid-August, last week began full commercial service on its 2-Bcf/d greenfield route from the Permian to South Texas. Actual volumes on GCX are hard to come by, but all indications are that flows are ramping to near capacity. That surge in Permian outflows in recent weeks has propelled natural gas prices at the regional benchmark Waha Hub — which traded as low as $5.00/MMBtu below zero earlier this year and fell into negative territory as recently as August 8 — to nearly $2/MMBtu, levels not seen at the hub since last winter. However, with the sting from negative prices only now just fading, many in the market are wondering if this rally is here to stay or just a temporary reprieve. Today, we look at the latest developments in the Permian natural gas market.