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.
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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.
What started out as a novel snow day for parts of Texas, replete with Facebook posts full of awestruck kids and incredulous native Texans, quickly escalated to a statewide energy crisis last week. A lot of the state’s electric generation and natural gas production capacity was iced out just when demand was highest, sending gas and electricity prices soaring and leaving millions without power for days. Frigid temperatures like the ones we saw would register as a regular winter storm in northerly parts of the U.S. and in Canada — but in Texas? A disaster. Market analysts, regulators, and observers will be unpacking the events of the past week — and the many implications — for a long time to come. We may never know the full extent of the chaos and finagling that went on among traders and schedulers behind the scenes as they tried to wrangle molecules. However, we can get some insight into the madness using gas flow data to provide a window into how the market responded and, in particular, the effect on LNG export facilities. Today, we examine the impacts of Winter Storm Uri on Gulf Coast and Texas gas movements.
If you’re reading this, it means you’ve got access to power and internet. Count yourself among the fortunate today. Rolling blackouts and brownouts across the middle of the country and in Texas, have disrupted businesses and lives. It’s been particularly brutal in the Lone Star State. Electricity and natural gas are commodities that are so basic to our way of living that it’s easy to take for granted the efforts designed to make them reliable, available, and affordable. But, boy, does it make things difficult when they don’t show up as anticipated. In today’s blog, we discuss the factors behind the supply disruptions that are wreaking havoc in these commodity markets.
Physical natural gas spot prices in the U.S. Midcontinent trading as high as $600/MMBtu, while Northeast prices barely flinch – that was the upside-down reality physical traders were contending with Friday in trading for the long weekend, with Winter Storm Uri bearing down on large swaths of the Lower 48 and spreading bitter-cold, icy weather from the Midwest and Northeast to Texas and the Deep South. The record-shattering, triple-digit spot prices, mostly all west of the Mississippi River, were indicative of some of the worst supply shortages the market has seen during the generally oversupplied Shale Era, or ever. But the East vs. West price divergence also marks the culmination of years of shifting gas supply and flow patterns that have redefined regional dynamics. The market will be digesting the various impacts of this still-unfolding event for days, but some of the effects and implications can be gleaned already from daily pipeline flows. In today’s blog we provide an early look at the market impacts of the polar plunge.
Weather is the perpetual wildcard in the natural gas market, but it’s been particularly shifty this winter, keeping market participants — and weather forecasters, for that matter — on their toes. Gas futures prices started this season at $3.30-plus/MMBtu, but then endured some of the warmest weather on record (in November and January), including a couple of polar vortex head fakes over the past month or so — weather forecasts at times in January started off much colder but ultimately reversed course. Prompt CME/NYMEX Henry Hub futures prices have seesawed as a result. Despite the weather setbacks, however, prices have held on in the $2.40-$2.70/MMBtu range through much of winter and averaged more than $0.60/MMBtu higher year-on-year in January. And, with an Arctic blast set to unfurl across the Lower 48 this week, prices last Friday topped $3/MMBtu again in intraday trading before settling in the high-$2.80s/MMBtu Friday and Monday. Today, we examine the supply-demand factors underlying the recent price action, and prospects for sustained $3/MMBtu gas prices.
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.
Talk about whiplash! Not that long ago, the global LNG market was reeling from the effects of the pandemic: stunted demand, severe oversupply, brimming storage, and record low prices, all of which led to a squeeze on offtaker margins and mass cancellations of U.S. cargoes. Within a matter of months, however, the market has done a 180. Global supply has tightened significantly as cargoes can’t get delivered fast enough, and international LNG prices are near two-year highs. U.S. LNG exports and domestic feedgas demand are at record highs in December, for the second straight month. That’s not to say U.S. LNG producers and the domestic gas market are out of the woods. Cancellations are rearing their heads again — not because the demand isn’t there, but because of logistical constraints and a severe vessel shortage, which are injecting more uncertainty into the market. Today, we provide an update on domestic LNG exports and the immediate factors driving them.
No one could’ve seen the energy market disruptions of 2020 coming, and most of us are ready to write off what has been one of the most challenging years the industry has seen in a long time. Yet the events of the past year will most certainly define what unfolds in the New Year and beyond. To make sense of what 2020 will mean for the post-COVID era, we retooled and refreshed our models and forecasts to tackle the hard questions facing U.S. crude oil, natural gas, and NGL markets. As it turns out, beyond the immediate chaos of the pandemic, there is a new order taking shape, and that’s what we laid out in the RBN Fall Virtual School of Energy, sharing our results and the Excel spreadsheets behind the models to get you ready for what’s coming. Some of what we expected has come to fruition, and we still think that there is a pretty good chance that the rest will unfold in the months and years ahead. If you weren’t able to join us for the live broadcast, we invite you to sit by the fire, put your feet up and dig in over the holidays. The entire 14+ hours of streaming content, plus slide decks and spreadsheets, are available online. Today’s advertorial blog provides highlights from our key findings and the overall conference curriculum.
Natural gas economic shut-ins! Shutting off a producing well on purpose, because the market won’t take the produced volume at a reasonable price. There was a time, back before gas commodity decontrol, when shut-ins were standard operating procedure, but that practice went the way of the dodo bird 40 years ago. Until earlier this year that is, when amid crushingly low prices, Appalachian producers said: enough is enough — and shut off the spigot themselves. In the months that followed, various producers have continued to see-saw their production in response to weather-related demand and regional market prices. The behavior signals that Appalachia’s shale gas producers are increasingly employing a light-switch approach in dealing with short-term weakness in demand and prices. Today, we take a closer look at the price-driven curtailments in the Northeast and potential implications for the market.
You wouldn’t know it from the $2.50-plus/MMBtu Henry Hub prompt natural gas futures prices in the past couple of months, but the U.S. gas market this injection season just barely managed to avoid a complete meltdown. Despite gas production volumes trailing year-ago levels all summer long, it wasn’t until the last month or two of the traditional injection season (April through October) that the market tightened enough to escape a major storage crunch. In reality, it took the multi-pronged effects of production cutbacks — in part from hurricane-related disruptions — higher LNG and pipeline exports, and cooler fall weather, to make that happen. Today, we review the U.S. natural gas supply/demand balance and implications for 2021.
With the rise of LNG feedgas demand in southern Louisiana, physical natural gas flows at Henry Hub have been climbing. As such, volumes moving through the U.S. benchmark pricing location are increasingly affected by swings in LNG feedgas deliveries, as well as in the gas supply flows into southern Louisiana that serve that demand. Those impacts have become particularly evident in recent months as nearby LNG export capacity utilization went from a trough this summer due to cargo cancellations, to being erratic during late summer and fall as hurricanes disrupted marine traffic and facility operations, and, in more recent days, to being at full bore at most facilities. In conjunction with brimming storage and pipeline maintenance in the area, this has meant more operational constraints and volatility in flows and pricing at the hub. Today, we continue our series on the changing dynamics in and around Henry Hub.
Since August, physical natural gas flows at Henry Hub have been at all-time highs for each respective month, and, in early October, they recorded the highest single-day flows that we’ve seen since December 2009. For decades, liquidity at the U.S. natural gas benchmark pricing location in southeastern Louisiana has been dominated by financial trades, with minimal physical exchange of gas, despite the hub boasting robust physical infrastructure and ample pipeline connectivity. That’s still the case, but physical movements of gas in the area have been on the rise due to LNG exports ramping up from the Sabine Pass and Cameron LNG facilities in southwestern Louisiana and a slew of Appalachia gas supply pipelines targeting that export demand. As more physical gas is moving through the hub, operational constraints are developing at key interconnects there. That, along with the ups and downs of LNG feedgas demand, is contributing to spot price volatility at the hub and, at times, a deeper divergence between Henry spot and futures prices. Today, we begin a short blog series on the changing gas flow dynamics in and around Henry.
2020 has been as anomalous as it can get for energy markets, but that’s especially the case for the LNG sector, which was battered by COVID-related demand destruction. U.S. export volumes, in particular, experienced wild swings this year, going from steady increases and close to 100% utilization over the past few years as new export capacity was added, to operating at barely 30% of capacity this past summer as national lockdowns decimated demand and led to historically low gas prices abroad. Contracted cargoes were canceled en masse for the first time since the U.S. began exporting in 2016, amounting to over 500 Bcf between June and September that was pushed back into the U.S. natural gas market and into storage. But these events only exaggerated what was already a growing risk; with each new train being commercialized, domestic markets are increasingly exposed to the demand swings and other fundamentals in the export markets it serves. Today, we look at how seasonal demand patterns in the U.S.’s primary destination markets could translate to increased volatility at home.