Natural gas markets in the U.S. Northwest have been in turmoil ever since a rupture on Enbridge’s BC Pipeline system over a month ago (on October 9) disrupted Canadian gas exports to Washington State at the Sumas border crossing point. Service on the affected line has been restored but at a reduced operating pressure for now, and Canadian gas deliveries to Sumas remain at about half of their pre-outage levels, creating supply shortages in the region. Spot natural gas prices at the Sumas, WA, trading hub have been volatile, soaring well above Henry Hub and rocketing to a record outright price of nearly $70/MMBtu late last week. The outage has reverberated across the Western U.S. gas market, sending regional prices reeling as gas flows adjusted to help offset supply shortages. Today, we examine the knock-on market effects of the outage on Western gas flows and prices, and potential implications for the winter gas market.
The U.S. natural gas market enters winter this year in a delicate balance: production is at an all-time high and growing fast, but gas storage inventories are well below year-ago levels and the five-year average — and at an all-time low relative to consumption. If winter weather is normal or mild, the U.S. gas market will likely begin to settle into a period of sub-$3/MMBtu prices. But this year’s low inventory level means that colder-than-typical weather this winter could spell more gas price upside than the market has seen in many years. Today, we continue our review of the current gas market with a look at the relationship between gas- and coal-fired generation, and at how the combination of low gas storage inventories and low coal stockpiles might play out this winter.
With recent project completions, Northeast takeaway constraints have eased, and regional supply prices have strengthened. But now the slate of planned pipeline expansions is dwindling. Between late-2015 and the end of 2018, midstreamers will have completed 23 takeaway projects out of Appalachia, totaling nearly 14.5 Bcf/d of capacity. That leaves just a handful of projects with little more than 6 Bcf/d of capacity to come, most of them facing stiff environmental opposition, regulatory turmoil and higher costs. Yet, as Appalachian gas production continues to grow, these projects will be critical to keeping the takeaway constraints and depressing supply pricing from returning, at least for a little longer. More than half of the remaining capacity would come from two competing projects — Dominion Energy’s Atlantic Coast Pipeline (ACP) and EQM Midstream Partners’ Mountain Valley Pipeline (MVP) — both greenfield efforts tied to growing gas-fired power generation demand along the Mid- and South-Atlantic seaboard and both embattled by a barrage of legal challenges. In today’s blog, we provide an update on the Atlantic Coast and Mountain Valley projects, including the latest status and timing.
The Energy Information Administration (EIA) estimates that natural gas gross production in the Rockies’ Niobrara region increased to a record 5.1 Bcf/d in September 2018, narrowly beating the previous high mark set almost seven years ago. And, with major, crude oil-focused producers in the Powder River Basin (PRB) and Denver-Julesburg Basin (D-J) planning for expanded crude output in 2019 and beyond, production of associated gas is expected to continue rising. All this growth — actual and anticipated — is spurring the development of new midstream capacity, especially gas processing plants, in both the PRB and the D-J Basin. So, what’s already in place, what’s being built and planned, and how soon will it need to come online? In today’s blog, we continue our review of Rockies crude oil, gas and NGL production, processing capacity and takeaway pipes, this time with a look at the gas side of things in the PRB.
Gas-fired power generation in the U.S. has been making impressive gains lately and that trend looks likely to continue. Power demand is growing quickly and generation fueled by cheap natural gas is taking an ever-increasing market share of the new and existing load from more expensive generators like coal and nuclear, which is leading significant numbers of those plants to shut down. The Energy Information Administration (EIA) earlier this year forecast that combined-cycle, gas-fired generation capacity could rise by 6.1 GW between now and 2020, which — if fully called upon — would equate to roughly 1 Bcf/d of gas demand. That growth would displace some older gas-fired generation but also fill the void left by retiring coal-fired and nuclear power generators — two sectors EIA expects to decline over the next couple of years by 14.1 GW and 1.7 GW, respectively. What’s more, surging gas production and rapidly filling pipeline expansions in recent months suggest that gas-fired generation demand may be growing even faster than expected. Today, we take a look at how gas generation has been besting coal-fired plants on fuel costs in recent years, and at the string of nuclear and coal-fired generators that are being permanently retired.
U.S. Northeast natural gas producers will soon get another boost of pipeline capacity with direct access to Gulf Coast demand. TransCanada’s Columbia Gas and Columbia Gulf transmission systems are gearing up to place into service their tandem Mountaineer Xpress and Gulf Xpress expansions, which will allow another 1 Bcf/d of Marcellus/Utica gas to flow south as far as Louisiana. The new capacity should further ease takeaway constraints for moving gas out of the Northeast, potentially redistributing outflows across the various takeaway routes, while also allowing Appalachian gas supply to grow. The duo of expansions is also the last of the southbound expansions from the Northeast, at least until late 2019, when the embattled Atlantic Coast and Mountain Valley projects are due online. Today, we detail the upcoming expansions.
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.
LNG Canada, the newly sanctioned liquefaction/LNG export project in British Columbia, is an entirely different animal than its operational and under-construction counterparts in the U.S. The Shell-led LNG Canada project is being developed without any of the long-term offtake contracts that financed Sabine Pass, Cove Point and the projects now being built along the Louisiana and Texas coasts, and it requires the construction of a new, long-haul pipeline — Coastal GasLink. What’s also different is that the BC project’s co-owners have been developing their own gas reserves to supply the project, though they may also turn to the broader Montney and Duvernay markets for the gas they will need. Today, we conclude a two-part series with a look at how the project expects to undercut its U.S. competitors.
U.S. natural gas supply continues to set all-time records, and strong production growth is expected to continue. Most of these supply gains will come from the Northeast, where another round of pipeline capacity additions are being completed. But despite all this incremental gas output, a combination of cold weather last winter and hot weather this summer means that U.S. gas storage inventories are likely to end the fall season at their lowest levels since 2005. And even this comparison understates how low inventories are — gas consumption has grown dramatically in the past 10 years, and storage inventories are at all-time lows when considered in terms of the number of days of average consumption. Today, we begin a series on the implications of historically low gas storage inventories, including what the gas market might look like if this winter turns out to be colder than normal.
Enbridge/DTE Energy’s 1.5-Bcf/d NEXUS Gas Transmission pipeline saw its first natural gas flows this week, as the Federal Energy Regulatory Commission (FERC) approved partial service on the project, opening another nearly 1 Bcf/d of capacity from Appalachia’s Marcellus/Utica producing region to the Midwest. NEXUS marks the last big westbound takeaway project from the Northeast, except for the remaining pieces of Energy Transfer’s (ETP) Rover Pipeline. It also marks the escalation of gas-on-gas competition in the Midwest market, where U.S. Midcontinent and Canadian gas supplies are also battling it out for market share. Today, we take a closer look at the NEXUS project and its potential implications for the Northeast and Midwest gas markets.
The final investment decisions by Royal Dutch Shell and its partners in the LNG Canada liquefaction and export project in British Columbia are a long-term boon to Western Canadian natural gas producers and to TransCanada, which now can proceed with its planned Coastal GasLink pipeline across the full breadth of BC. But the LNG Canada facility in Kitimat and the new 420-mile, 2.1-Bcf/d pipe won’t come online until 2023 — an eternity for producers in the region’s Montney and Duvernay shale plays, who through much of 2018 have been enduring profit-crushing price discounts for their gas relative to Henry Hub. Today, we consider the largest North American liquefaction/LNG export project to be sanctioned in several years, and why BC and Alberta producers wish it were coming online much sooner.
While many are getting ready for the usual trappings of fall — Halloween, Thanksgiving turkey and Black Friday sales — Northeast natural gas market participants are gearing up for their own seasonal ritual — gas pipeline takeaway expansions. Two days ago, Enbridge/DTE Energy’s 1.5-Bcf/d NEXUS Gas Transmission pipeline received approval to start partial service for nearly 1 Bcf/d of capacity. That follows Williams/Transco’s Atlantic Sunrise natural gas project, which launched service for its full 1.7 Bcf/d of southbound capacity last week (on October 6). Also last week, TransCanada/Columbia Gas Transmission was given the nod for partial service on both its Mountaineer Xpress and WB Xpress projects. Then there’s Energy Transfer’s Rover Pipeline, which is awaiting approval for its final two laterals. Combined, these projects are poised to add more than 4.0 Bcf/d of Marcellus/Utica takeaway capacity before the coldest months of winter arrive. What does that mean for the Northeast gas market this winter? Today, we provide an update on Atlantic Sunrise’s early effects and other upcoming projects completions.
With the addition of new large-diameter natural gas pipelines like Energy Transfer Partners’ Rover Pipeline and Enbridge and DTE’s NEXUS Gas Transmission, the dog days of severely depressed gas prices in the U.S. Northeast will be diminishing (though not disappearing entirely), but they are just getting started for its downstream markets. After years of constrained natural gas supply growth, Northeast takeaway capacity appears to be outpacing regional production volumes more and more, and RBN’s analysis of production economics suggests that, left unconstrained, the Marcellus/Utica gas market is set to unleash an incremental 8 Bcf/d into the broader U.S. gas market by 2023, with the bulk of that volume targeting consumption in the Midwest and Gulf Coast regions. In today’s blog, we walk through our outlook for Northeast takeaway capacity and gas production, and by extension, U.S. gas supply.
It’s crunch time in the race to advance the next-round of liquefaction/LNG export projects along the U.S. Gulf Coast to a Final Investment Decision (FID). And if we’re to assume that only a small number of these multibillion-dollar projects will get their financial go-aheads, it would seem eminently reasonable to put a win-place-or-show bet on a joint venture that includes the world’s leading LNG producer (by far) and one of the largest U.S. natural gas producers — oh, and the partners have very fat wallets too. Size and money aren’t everything, of course, but as we discuss in today’s blog, the team behind the Golden Pass LNG project plans to build its liquefaction trains at the site of an existing LNG import terminal with strong interconnections with coastal pipelines already in place.
Florida’s electric utilities are turning to natural gas-fired power and renewables for all their incremental generation needs and as replacements for the older coal units they’ve been retiring. The state’s big bet on natural gas has been spurring the development of new pipelines. And, because of big shifts in where gas is being produced and where it’s flowing, the Sunshine State will soon be receiving an increasing share of its gas needs from the Marcellus region. Today, we discuss the slew of new gas-fired power plants that have come online, the additional plants planned, and gas flows on Sabal Trail, the first new gas mainline into the state in almost two decades.