Lower crude oil prices whack oil-directed drilling, slashing crude production, which cuts associated gas output, tightening the gas supply-demand balance, and boosting gas prices enough to spur more gas-directed drilling — it’s a classic case of commodity market schadenfreude, where one product benefits at the expense of another. That’s the way it was supposed to work, according to various trading strategies touted a few weeks back. But here we sit, with crude oil prices still around $40/bbl and gas prices languishing at a paltry $1.66/MMBtu. Was there something wrong with the schadenfreude thesis, or do we have to look deeper to understand how prices will behave in this convoluted COVID era? In today’s blog, we’ll explore this question and what it may mean for natural gas prices in the coming months.
U.S. Northeast natural gas production has tumbled nearly 900 MMcf/d in the past month alone since EQT Corp., Cabot Oil & Gas, and others began curtailments in response to low gas prices, and is averaging nearly 2 Bcf/d below last November’s peak of 32.9 Bcf/d. But regional gas demand has lagged this year, storage inventories have surpassed five-year highs and outbound flows to the Gulf Coast are being challenged by reduced takeaway capacity and drastically lower demand from LNG export facilities. Today, we examine the net impact of these competing fundamental factors on the region’s supply-demand balance and the resulting implications for Appalachian supply prices.
U.S. Northeast natural gas producers may be on the other side of a years-long battle with perpetual pipeline constraints and oversupply conditions. But they’re now facing new challenges to supply growth, at least in the near-term, from low crude oil and gas prices and the decline of a major downstream consumer of Appalachian gas supplies: LNG exports along the Gulf Coast. Most of the U.S. well shut-ins since the recent oil price collapse are concentrated in oil-focused shale plays, and gas volumes associated with those wells will be the hardest hit. However, a number of gas-focused Marcellus/Utica producers also have announced or escalated supply curtailments in recent weeks, as they wait for associated gas declines to buoy prices enough to support drilling. The pullback has had immediate effects on the region’s production volumes and supply-demand balance. Today, we provide an update on the latest Appalachia gas supply trends using daily gas pipeline flow data.
The development of Appalachia’s Marcellus and Utica shales has flipped regional natural gas prices in the U.S. Northeast from their long-time premiums to Henry Hub, to trading at a significant discount and, in the process, reversed inbound gas flows, including from Eastern Canada. But there is an exception: from an entry point at the northern edge of New York, the Iroquois Gas Transmission pipeline is still importing Canadian gas supply nearly year-round to help meet local demand, despite its proximity to Marcellus/Utica production via other Northeast pipelines. This has kept prices along the Iroquois pipeline system at a premium to the other points in the region. And with the new, 1,100-MW Cricket Valley Energy Center power plant due online this spring, Iroquois prices are likely to strengthen. Today, we examine the dynamics driving Iroquois prices and gas flows.
For much of the 2010s, the U.S. midstream sector has been on a development spree. New or expanded everything — pipelines, gas processing plants, fractionators, storage facilities, liquefaction trains, export terminals and more — all to keep pace with the production gains of the Shale Era. But now, at the start of the 2020s, the build-out frenzy appears to be fizzling and flickering. Midstreamers’ capital spending plans are on the decline, at least for now, as most of the infrastructure needed to handle current and expected volumes for the next few years is either in place or under construction. But that doesn’t mean things won’t stay interesting — far from it. This new decade brings with it a period of midstream-sector strategizing and portfolio rejiggering. Today, we discuss highlights from East Daley Capital’s newly released “Dirty Little Secrets” report about the next phase of midstream strategy.
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.
The “wet,” liquids-rich parts of the Marcellus/Utica region enable producers there to benefit from the sale of both natural gas and NGLs. The catch is that, unlike major production areas in other parts of the U.S., the Northeast has no pipelines to transport unfractionated, mixed NGLs — also known as y-grade — long distances to fractionation centers in Mont Belvieu, TX, or Conway, KS. As a result, midstream companies serving the region have developed a number of interconnected gas processing, NGL pipeline and fractionation networks within the wet Marcellus/Utica to efficiently and reliably deal with the increasing flows of NGLs coming their way. No one has done this on a larger or more impressive scale than MPLX, Marathon Petroleum Corp.’s midstream-focused master limited partnership. Today, we continue our series on recently completed and planned gas processing and fractionation projects in the Northeast with a look at MPLX, the regional leader in this space.
Natural gas production in the U.S. Northeast has been increasing steadily through the 2010s and now averages about 32 Bcf/d — 12% higher than last August and nearly double where it stood five years ago — despite the lowest regional spot gas prices since early 2016. This run-up in production volumes wouldn’t have been possible without the new gas-processing and fractionation capacity that MPLX and other midstream companies have been bringing online at a steady pace in the “wet” or NGLs-rich parts of the Marcellus and Utica shales. Today, we begin a short blog series on recently completed and planned gas-processing and fractionation projects in the nation’s largest gas-producing region, and the gas production growth they will help enable.
TC Energy’s Columbia Gas and Columbia Gulf natural gas transmission systems’ recent expansions out of the Northeast — the Mountaineer Xpress and Gulf Xpress projects, both completed in March — are responsible for a large portion of the uptick in Marcellus/Utica production in the last few months and they’ve added an incremental 860 MMcf/d of capacity for Appalachian gas supplies moving south to the Gulf Coast. The two projects join a number of other expansions in recent years that have inextricably tied Marcellus/Utica supply markets to attractive demand markets along the Texas and Louisiana coasts. Where is that latest surge of southbound supply ending up? Today, we look at the downstream impacts of the completed projects, namely on Louisiana gas flows and LNG feedgas deliveries.
U.S. Northeast natural gas producers in recent months got a substantial boost in pipeline capacity to receive and move incremental gas production volumes to attractive Gulf Coast markets. TC Energy’s Columbia Gas and Columbia Gulf transmission systems in March completed the Mountaineer Xpress and Gulf Xpress pipeline expansions, respectively, increasing the combined system’s Marcellus/Utica receipt capacity by 2.7 Bcf/d in the producing region, while also bumping up the Marcellus/Utica’s takeaway capacity to the Gulf Coast by nearly 900 MMcf/d. The duo of expansions is among the biggest takeaway capacity additions to be completed out of the Northeast, volume-wise, and among the handful that inextricably connect Marcellus/Utica supply markets to well-sought-after LNG exports markets along the Texas and Louisiana coasts. One of the export terminals these projects are designed to serve is Sempra’s Cameron LNG, where Train 1 began commercial operations in recent weeks. Today, we provide an update on the upstream and downstream implications of the recently installed Northeast-to-Gulf Coast pipeline capacity.
A raft of natural gas pipeline projects completed in the past couple of years has — for the first time — left room to spare on most takeaway routes out of the Northeast and provided Marcellus/Utica producers a reprieve from the all-too-familiar dynamic of capacity constraints and heavily discounted supply prices, even as regional production continues achieving new record highs. There’s on average close to 4 Bcf/d of unused exit capacity currently available — more in the winter when higher in-region demand means more of the production is consumed locally and less than that (but still more than in past years) in the spring, summer and fall seasons, when greater outbound flows are needed to help offset the relatively lower Northeast demand. But we’re expecting Northeast production to grow by another 8 Bcf/d or so over the next five years. And the list of projects designed to add more exit capacity has dwindled to just a few troubled ones that, even if built, wouldn’t be enough to absorb that much incremental supply. When can we expect constraints to re-emerge? Today, we conclude this series with a look at RBN’s natural gas production forecast for the Marcellus/Utica and how that correlates to the region’s pipeline takeaway capacity over the next five years.
Just two years ago, severe transportation constraints and steep price discounts were part and parcel of the Northeast natural gas market. Midstreamers were racing to add much-needed pipeline capacity out of the region, but not fast enough for producers. It was an inevitability that any pipeline expansions would instantaneously fill up. Gas production records were an almost monthly or weekly occurrence, and just as unrelenting were the takeaway constraints and pressure on the region’s supply prices. Not so today. Northeast gas production in June posted a record high, with the monthly average exceeding 31 Bcf/d for the first time. Yet, June spot prices at Dominion South, Appalachia’s representative supply hub, were the strongest they’ve been in six years relative to national benchmark Henry Hub. Why? The spate of pipeline expansions and additions in the past two years have not only caught up to production but capacity now far outpaces it, and consequently, producers now have something they haven’t had in a long time — optionality. Today, we break down how much spare capacity is available and its effect on regional pricing.
The Northeast gas market has come a long way since 2013, when it first began net exporting gas supply to the rest of the U.S. The past several years were marked by dozens of pipeline expansions to relieve takeaway constraints and to balance oversupply conditions in the region; as a result, takeaway capacity is finally outpacing production growth. How much spare capacity is there now, and how long will it be before production growth hits the capacity wall again? Today, we continue our series on Northeast gas takeaway capacity vs. production, this time examining the utilization of pipes in the Northeast-to-Gulf Coast corridor.
Natural gas pipeline takeaway capacity additions out of the Northeast over the past year or two, along with suppressed gas production growth in recent months, have relieved years-long and severe constraints for moving Marcellus/Utica gas out of the region and even left some takeaway pipelines less than full. That, in turn, has supported Appalachian supply prices. Basis at the Dominion South hub in the first five months of 2019 averaged just $0.26/MMBtu below Henry Hub, compared with $0.46 below in the same period last year and nearly $1.00 below back in 2015, when constraints were the norm. Today, we continue our series providing an update on pipeline utilization out of the region, and how much spare capacity is left before constraints reemerge.
The Northeast natural gas market turned a new leaf in 2018, when takeaway pipeline capacity to move supply out of the Marcellus/Utica producing region finally caught up to — and even began outpacing — production growth. More than 4 Bcf/d of takeaway expansions entered service in 2018. Prices at the region’s Dominion South supply hub improved relative to Henry Hub and other downstream markets. And for the first time in years, Appalachian gas producers and marketers caught a glimpse of what an unconstrained, balanced market driven by market economics (as opposed to transportation constraints) could look like. 2019 will be the first full year of operation for many of those takeaway expansions that came online in 2018. Northeast production growth flattened through the first few months of 2019, but has ticked up in the past couple of months, albeit modestly, and the slate of future takeaway expansion projects has shrunk to just a couple stalled projects. Where does that leave capacity utilization out of the region this summer, and how long will it be before production growth hits the capacity wall again? Today, we begin a series providing an update on the Northeast gas market and prospects for balancing takeaway capacity with production growth.