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.
Daily Energy Blog
Over the past quarter-century, through a combination of greenfield development and acquisitions, Energy Transfer (ET) has built out integrated networks of midstream assets that add value — and generate profits — as they move crude oil, natural gas, and NGLs from the wellhead to end-users. A couple of weeks ago, ET took another big step in its expansion strategy, announcing its plan to buy Enable Midstream in a $7.2 billion, all-equity deal expected to close in mid-2021. The assets to be acquired will augment the synergies ET has already achieved, particularly regarding NGL flows into its Mont Belvieu fractionation and export facilities as well as flows of natural gas through Louisiana’s central gas corridor to LNG and industrial demand on the Gulf Coast. Today, we examine how the Enable Midstream acquisition may help propel ET forward.
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.
The February 2021 polar vortex will be one for the natural gas record books in the U.S. and Canada — and the month isn’t even over yet! Though no stranger to frigid weather, Canada’s natural gas market has felt the impacts of this month’s extreme cold on both sides of the border. Its own prices, demand, and storage withdrawals have reached multi-year or all-time records as gas buyers have jockeyed for molecules from anywhere they can get them. Gas exports to the U.S. have reached highs not seen for more than a decade, adding emphasis to what has been an emerging turnaround story for Canadian gas into the U.S. market. To top things off, the latest gas market records might be a preview of what is to come in the next few years as Canada’s structural demand for natural gas continues to increase, regardless of how cold it is. Today, we describe all the latest Canadian gas market action and what might be in store for next winter.
There’s finally some good news for folks in Texas: it’s gradually getting warmer, and the power outages that left much of the Lone Star State in the cold and dark the past few days should keep winding down. But what are we all to make of what just happened? How could a state blessed with seemingly limitless energy resources of every type — natural gas, coal, wind, and solar among them — end up so short of electricity when it needed power more than ever? It turns out that the electric grid that the vast majority of Texans depend on day in, day out is designed to perform very well almost all the time, but is susceptible to a rapid unraveling when an unfortunate combination of events hit. Today, we continue our review of how this week’s extraordinarily low temperatures have been impacting energy markets — and many of us.
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.
Permian producers and midstreamers have faced a lot of uncertainty over the past 12 months. First, they wondered how much demand destruction would be caused by pandemic-related lockdowns, how low crude oil prices might fall, and how much production would be cut back and where. Then, they needed to assess how quickly demand, prices, and production levels would rebound, and determine whether the gathering systems, gas processing plants, and other infrastructure they had been planning pre-COVID should proceed according to their original schedules or be delayed or even canceled. As it turned out, most of the projects went ahead, the developers anticipating — correctly, it now appears — that if any U.S. production area will keep growing, it will be the Permian. Today, we continue a short blog series on gas-related infrastructure development in 2020-21, this time focusing on the Delaware Basin.
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.
The biggest news on the Permian natural gas infrastructure front in the past couple of months was surely the start-up of the 2-Bcf/d Permian Highway Pipeline (PHP), which began flowing gas in the fourth quarter of 2020 and officially entered full commercial service on New Year’s Day. Next among the headlines would be the late-January completion of a 1.8-Bcf/d expansion of the Agua Blanca pipeline system, which increased the capacity of the Delaware Basin-to-Waha network to a staggering 3 Bcf/d. Just as important though is that midstream companies active in the Permian have been completing a number of new gas processing plants in key production areas within both the Midland and Delaware basins, thereby supporting the continuing development of the U.S.’s premier crude oil production region. Today, we begin a short series on all the new gas-handling capacity coming online in the Permian.
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.
In the past few years, the Netherland’s Title Transfer Facility (TTF) overtook the UK’s National Balancing Point (NBP) to become the premier gas trading hub in Europe. TTF has gained favor over NBP largely due to its location closer to more markets, supply pipelines, plentiful storage, and also the Netherlands’ Gate LNG import terminal, which has become paramount given Europe’s growing need for imported gas. As imports have grown, so has TTF in terms of its volume and its liquidity — a trend that is expected to continue as the European gas market evolves. TTF now shares the stage with Henry Hub and the Japan Korea Marker (JKM) as one of the key global benchmarks for LNG and natural gas. Though traders use TTF as a price index for LNG, much like its cross-Atlantic peer, Henry Hub, TTF is also heavily influenced by regional pipeline gas and storage levels. Today, we’ll look at the history of Europe’s premier natural gas index and the fundamentals affecting it.
There are no absolute certainties in the energy industry, but one thing a lot of people are betting on is increasing demand for LNG in Asia. A long list of countries there — China, Japan, and South Korea among them — have been shifting from nuclear and coal-fired power generation to natural gas, and as they do, their demand for LNG will be mind-blowing. The U.S. has emerged as a major supplier, but shipping LNG from the Gulf Coast to Asia involves either transiting the busy and costly Panama Canal or taking much longer routes through the Suez Canal or around the Cape of Good Hope. All of that has helped spur interest in developing LNG export terminals in western Mexico that would pipe in and liquefy Permian gas, then ship it straight across the Pacific Ocean. Today, we discuss plans for a large-scale liquefaction/export project aimed squarely at Asian buyers.
If you are looking for a way to focus on 2021 without reflecting on the last 12 months, we might have a deal for you. That’s because Permian natural gas and oil production is starting off this year at levels very close to where they finished 2019. That’s right: as far as the Permian is concerned, you can almost skip entirely over 2020 and pick up right where we left off the prior year. Well, for the most part. Oil prices are lower, rig counts have been reduced, and industry consolidation has removed some of the familiar Permian names from the stock ticker. In general, the atmosphere out in West Texas has calmed down dramatically from the headiest days of Permian growth and it’s safe to say it’s easier to grab lunch in Midland these days. Does that mean things in the basin aren’t still interesting out there? If you ask us, the answer is a resounding “No!” For starters, growth is back in the basin, even if it is at a slower pace than in 2019, and natural gas prices are stronger, with negative-price trades a thing of the past thanks to new pipelines. Even crude prices are better than some might think, with Permian barrels pricing over Cushing for many months now. The Permian in 2021 is certainly a half-empty or half-full type of market. We go for the latter in today’s blog, in which we outline our view of production growth in West Texas this year.
