While it’s widely known that Canada’s natural gas prices and exports have been under increasing pressure from rising gas supplies in the U.S., forcing an ever-deeper discount for AECO — Canada’s primary gas price benchmark — versus U.S. benchmark gas prices, a homegrown development is making the situation worse. Growing unconventional gas supplies from the Montney and related plays in Western Canada are bumping up against insufficient pipeline takeaway capacity from this producing region. Will Canadian gas markets be able to adapt to all of these growing supplies on both sides of the border or simply wither away as U.S. supplies take more and more market share? Today, we kick off a multi-part series examining the highly complex problems facing Western Canadian gas producers.
Permian natural gas prices have been on a wild ride lately, trading more than $5/MMBtu below zero in early April before recovering to just above zero over the last few weeks. It’s hardly a secret that the Permian’s gas market woes have been the direct result of production exceeding pipeline capacity. That situation is set to change in a few months, when Kinder Morgan starts up its 1.98-Bcf/d Gulf Coast Express Pipeline, providing much needed new takeaway capacity. And that’s not all GCX will do. Its start-up will shift huge volumes of gas toward the Texas Gulf Coast that currently flow out of the Permian to other markets, likely causing a ripple effect across more than just the West Texas gas market. Today, we look at how Kinder Morgan’s new gas pipeline will redirect significant volumes of Permian gas currently flowing north to the Midcontinent.
With U.S. natural gas production levels near all-time highs and storage injections running strong, LNG exports will be a critical balancing item for the domestic gas market this year. Yet feedgas demand in recent months has been anything but stable; rather, it’s proving to be susceptible to volatility, driven by a combination of offshore weather conditions, maintenance events, start-up activity and global market conditions, among other factors. At the same time, timelines for the remaining 20 MMtpa (2.6 Bcf/d) of new liquefaction capacity still due online this year are moving targets as coastal weather, construction-related delays and other variables affect target completion dates. Today, we discuss highlights from our new Drill Down Report on the impacts of recent and upcoming LNG export capacity additions.
The Texas natural gas market is rapidly evolving, in large part due to burgeoning Permian production but also due to gas production gains in East Texas driven by strong returns on new wells in the Haynesville and Cotton Valley plays. Most of this supply growth is looking to make its way to the Gulf Coast, where close to 5 Bcf/d of LNG export capacity is operational and plenty more is under construction. The combination of fast-rising supply and demand is straining the existing gas pipeline infrastructure across Texas, creating the need for more capacity. The Permian has been grabbing the headlines for its extreme takeaway constraints and depressed, even negative supply-area prices, and all eyes are trained on the announced pipeline projects that will eventually provide relief to the region. But pipeline constraints also are developing between the Haynesville and the Texas coast. Today, we discuss the latest solution for the intensifying Haynesville-area supply congestion.
The cascade of LNG export project news continues. In the past week, yet another “second-wave” U.S. LNG export project — NextDecade’s Rio Grande LNG — cleared FERC’s environmental review process. That follows news of three other projects that received their environmental approvals this month; plus two other projects — Tellurian’s Driftwood LNG and Sempra’s Port Arthur LNG — got final FERC authorization to construct their facilities, should they make the financial commitment to proceed; and, finally, plans for a brand new export terminal, Venture Global’s Delta LNG, were unveiled. All in all, there are more than 20 announced projects totaling 235 MMtpa (~35 Bcf/d) that are looking to catch the second wave of U.S. LNG exports in the next decade. The timing of their regulatory approvals and final investment decisions will determine, in part, when this next wave — or shall we say tsunami — of export demand will materialize. Today, we wrap up our second-wave LNG project update series with a look at the progress made by some of the remaining projects that we’re tracking.
2019 is slated to be a watershed year for U.S. LNG export projects vying to catch the second wave — the first wave being the slew of liquefaction trains already operational or in the process of being commissioned or constructed. As expected, regulatory and commercial activity has heated up around the two dozen or so longer-term proposals to add liquefaction capacity along the U.S. coastlines over the next decade. Last week, the Federal Energy Regulatory Commission (FERC) approved two of those projects — Tellurian’s Driftwood LNG and Sempra’s Port Arthur LNG — and several others, including Driftwood and NextDecade’s Rio Grande LNG, also have made progress on the commercial front. Many of these projects are targeting a final investment decision (FID) this year. Today, we continue a series highlighting the second-wave projects’ latest developments.
It’s said that everything is bigger and better in Texas, and when it comes to the magnitude of negative natural gas prices, the Lone Star State recently captured the crown by a wide margin. By now, you’ve probably heard that Permian spot gas prices plumbed new depths in the past couple of weeks, falling as low as $9/MMBtu below zero in intraday trading and easily setting the record for the “biggest” negative absolute price ever recorded in U.S. gas markets. Certainly, that was bad news for many of the Permian producers selling gas into the day-ahead market. But every market has its losers and winners, and negative prices were likely “better” — dare we say much better — for those buying gas in the Permian. Today, we look at some of the players that are benefitting from negative Permian natural gas prices.
The winter 2018-19 natural gas market was one of the most chaotic in recent memory, with the NYMEX Henry Hub futures contract last fall rocketing up to nearly $5/MMBtu in a matter of weeks, only to collapse in late 2018/early 2019 to an average $2.60 in January. The physical gas market also swung to extremes in recent months, setting both the highest ($200/MMBtu at the Sumas, WA, hub) and lowest (negative $9.00/MMBtu at the Waha hub) trades ever recorded in the U.S. These anomalies occurred amid steep supply growth from the Marcellus/Utica and Permian producing regions and rapidly advancing demand, particularly from burgeoning LNG exports along the Gulf Coast, while infrastructure scrambled to keep pace to bridge the two. And there’s more of that volatility ahead. Close to 5 Bcf/d more LNG export capacity is being added this year alone, and Lower-48 gas production is poised to continue growing. Today, we lay out our view of the recent volatility and the biggest factors shaping the gas market over the next five years, based on Rusty Braziel’s Backstage Pass Fundamental Webcast last week.
The shutdown of natural gas production from the Sable Offshore Energy Project on Canada’s East Coast as of January 1, 2019, increased the Canadian Maritimes’ reliance on gas exports from New England this winter as consumers worked to link up with fresh supply to replace SOEP. The tightening supply in the region has prompted expansion plans from TransCanada to move more Western Canadian and Marcellus/Utica gas to New England utilizing its Mainline and other eastern systems. Today, we conclude our series examining the potential impacts of SOEP’s demise by examining new plans to bring more gas to the region.
Ten weeks after an explosion crippled a key natural gas takeaway route out of the Marcellus/Utica, the capacity finally has been fully restored. Texas Eastern Transmission two days ago said it’s lifting all restrictions on the affected section of pipe. The outage began on January 21 and partial service resumed eight days later, but TETCO’s Northeast production receipts during the event averaged about 700 MMcf/d lower than usual and the line’s flows to the Gulf Coast were cut by 30-40%. That, along with two severe polar-vortex periods in January that overlapped with the outage, caused a reshuffling of flows across other pipelines in the region. Today, we wrap up this series with a look at the implications of the outage on the Northeast gas market and what to expect now that it’s ended.
Midstreamers have been struggling to keep processing and natural gas pipeline constraints at bay in Oklahoma’s SCOOP/STACK plays, and the situation hasn’t gotten any easier in the past 18 months or so. Associated gas production from the Cana-Woodford has surpassed expectations, climbing 1 Bcf/d in that time to new highs near ~4.5 Bcf/d. Efforts by pipeline operators to keep pace with production gains have largely been on a piecemeal basis, mostly to tie in processing plants or modify/expand existing systems. Cheniere Energy’s Midship Project is looking to change that. The greenfield project, which received its final notice to proceed with construction from the Federal Energy Regulatory Commission (FERC) late last month, will level-shift takeaway capacity out of Oklahoma up by 1.44 Bcf/d in one fell swoop by the end of 2019. Today’s blog provides an update on Midship and other expansions in the region.
Permian natural gas prices are having a rough spring. After a volatile winter that saw two periods of negative-priced trades followed by a period of relatively strong prices, values at the Permian’s major trading hubs hit the skids earlier this week just as Spring Break set in for most in the Lone Star state. Once again, pipeline maintenance and burgeoning production appear to be the main culprits, but this upheaval feels different, in our view. Clearly, the price crash has reached a new level of drama, with day-ahead spot prices at West Texas’s Waha hub now settling below zero — some days by more than $0.50/MMBtu. Gas production has raced higher too, now within striking distance of 10 Bcf/d, on the coattails of continued oil pipeline capacity expansions, but new gas pipeline takeaway capacity is an estimated six months away. What becomes of Permian gas prices in the meantime, and how much worse could already-negative prices get? Today, we discuss the drivers behind the latest price deterioration and assess what’s ahead for the Permian natural gas markets.
The second wave of North American LNG export projects is officially underway. LNG Canada took final investment decision (FID) last October and would be the first large-scale LNG export facility in Canada. Golden Pass followed in February, marking the beginning of the next round of LNG export build on the U.S. Gulf Coast. Sabine Pass Train 6 is expected to get the green light any day, and at least eight more projects are targeting FID this year. But how likely are these projects to go ahead? And what exactly does it take for a project to reach that financial milestone? Today, we begin a two-part blog series on the factors affecting U.S. and Canadian LNG export projects’ prospects for taking FID and our view on the projects making progress towards joining the second wave of LNG exports.
After a period of delays, commissioning activity at the newest U.S. LNG export terminals is poised to accelerate in the coming months, in turn bringing on incremental feedgas demand. Sempra’s Cameron LNG has said it’s ready to introduce feedgas to its fuel system and is awaiting federal approval. Meanwhile, liquefaction projects at Kinder Morgan’s Elba Island LNG and Freeport LNG terminals are gearing up to take feedgas in the next month or so. Feedgas deliveries to the operating export facilities in the past seven days have averaged 5.5 Bcf/d. These three projects alone are slated to add another 1.2 Bcf/d of incremental feedgas demand by July, bringing the total to 6.7 Bcf/d by then, if all goes well. In today’s blog, we continue examining the status and timing of LNG export projects in 2019, this time with a closer look at the Cameron, Elba and Freeport projects.
Appalachia — the U.S.’s leading gas production region — is also one of the last bastions of coal country in the broader Northeast. That dual reality makes it one of the remaining pockets in the region where there is significant potential for upside in natural gas demand for power generation. Gas burn for power in the Appalachian states — Pennsylvania, Ohio, West Virginia and Kentucky — surpassed power burn in the northern Mid-Atlantic market (New York/New Jersey) in 2017 and led the growth in overall Northeast power burn in 2018. The availability of consistently low-priced gas in recent years has hastened the retirement of coal-fired and nuclear generation plants in the shale producing region and fueled the addition of combined-cycle gas-fired generators, with more scheduled to come online soon. Today’s blog looks at recent and upcoming changes in the Appalachian generation fleet, and their implications for gas demand growth.