This time last year, Appalachian natural gas production was approaching a steep springtime ledge as regional prices sank below economic levels and producers responded with real-time shut-ins. This year to date, regional gas prices have averaged $0.80-$0.90/MMBtu above 2020 levels for the same period, and production has been averaging more than 1 Bcf/d above year-ago levels. If production holds steady near current levels, the year-on-year gains would just about double to ~2 Bcf/d by mid-May, which is when the bulk of the springtime curtailments first took effect in 2020. This, just as Northeast demand takes its seasonal spring plunge, which means regional outflows are poised to rise in the coming weeks, potentially to record levels. How much more can the Appalachian takeaway pipelines absorb? In today’s blog, we continue our analysis of outbound capacity utilization, this time focusing on the routes to the Midwest.
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We started off this propane season worried about the threat to U.S. propane markets from big-time exports. With exports now exceeding total U.S. propane demand, how would propane markets respond if we ever got a really cold winter? Well, now we know. Frigid weather finally arrived in February with a vengeance. But the propane market handled it pretty well. Now, as we approach the end of propane winter and examine where the market stands with inventories, prices, and especially exports, the big question is, what happens next? Will production volumes replace depleted stocks now sitting near a five-year low, or will those barrels move overseas? Will strong global petchem demand pull supplies out of U.S. markets? And if so, what does that imply for the 2021-22 retail propane season here in the U.S. In today’s blog, we’ll begin an exploration of these issues and introduce our upcoming RBN virtual conference covering developments in the propane market scheduled for May 12. Warning! Some of today’s blog is an unabashed advertorial for the conference.
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.
The crude oil hub in Cushing, OK, is larger and grabs the headlines, but don’t you forget about the Patoka hub in south-central Illinois. It plays critically important roles in receiving Western Canadian, Bakken, and other crude, distributing it to a slew of Midwestern refineries, and directing oil south to the Gulf Coast on the Energy Transfer Crude Oil Pipeline to Nederland, TX — and soon on Capline to St. James, LA, when reversed flows on that large-bore pipe begin in early 2022. Better still, there are great stories behind the development of the Patoka storage and distribution hub and how it works. Today, we begin a series on the second-largest crude oil hub in PADD 2 and why, with the upcoming Capline reversal and other changes, the hub is more relevant than ever.
Many countries like to talk about energy independence, but Canada is one of the few to come close to that elusive goal. For many years, Western Canada has produced more than enough crude oil to satisfy the demand of refineries in the region. More recently, a combination of rising Western Canadian oil production, and new and reworked pipelines, has enabled many of Canada’s eastern refineries to increase their intake of Western Canadian barrels. In the few remaining cases where they can’t, imported barrels from the U.S. have filled the gap, leaving crude imports from overseas accounting for just 1% of the market. Not surprisingly, Canada is also a net exporter of refined products, with refiners in Western Canada, and especially Atlantic Canada, producing far more than the country’s demand. Today, we conclude our series on Canada’s refining sector with a look at its growing reliance on Western Canadian crude oil and its ability to meet most of Canada’s need for gasoline and distillates.
Week by week, more than 20 terminals along the U.S. Gulf Coast export crude oil, but nearly half of the total export volumes are being loaded at just three facilities: the Moda Midstream terminal near Corpus Christi, the Enterprise Hydrocarbon Terminal in Houston, and the Louisiana Offshore Oil Port (LOOP) off the Louisiana coast. What gives these “Big 3” their edge? Location? Pipeline connectivity? Storage capacity? Loading rate? The answer, of course, is “all of the above.” There is more to the story, though, and other terminals are angling to become bigger players, presumably at the expense of the Big 3 themselves. Today, we begin a series on Texas and Louisiana’s largest oil export facilities, what they offer, how they’ve fared, and what they’re planning next.
Many leading energy companies have come to accept the reality that environmental, social, and governmental (ESG) matters are now front-and-center concerns to an increasing number of investors and lenders. Their challenge, of course, is that the hydrocarbon-based commodities they produce, process, transport, and refine are by their very nature prospective generators of carbon dioxide and other greenhouse gases that the ESG movement is targeting. What’s an energy company to do? For many midstream companies, the answer — for now at least — is to focus on minimizing the release of methane, carbon dioxide (CO2), and other GHGs from their gas processing plants, pipelines, storage facilities, and fractionators, and on switching to renewables to power their operations. Today, we continues our series with a look at how midstream companies are addressing investors’ and lenders’ concerns about the sector’s GHG releases.
When it finally came online in mid-2017, the Dakota Access Pipeline was a lifesaver for Bakken crude oil producers. For years, they had suffered from takeaway-capacity shortfalls that forced many shippers to rely on higher-cost crude-by-rail, sapping producer profits in the process. Then came DAPL, which provides straight-shot pipeline access to a key Midwest oil hub, and its sister pipe — the Energy Transfer Crude Oil Pipeline (ETCOP) — which takes crude from there to the Gulf Coast. Problem solved, right? Not exactly. Now, there’s at least an outside chance that a shutdown order is issued as soon as early April in connection with the ongoing federal district court process, with the timeline for a physical closure of the pipe still to be determined. A shutdown may last for only a few months but could potentially last much longer. Where does this uncertainty leave Bakken producers, many of whom have been hoping to benefit from the recent run-up in crude oil prices by ramping up their output this spring? Today, we discuss recent upstream and midstream developments in the U.S.’s second-largest shale/tight-oil play.
Canada, like the U.S., is in the enviable position of having vast crude oil reserves as well as a robust domestic refining sector capable of satisfying national needs for gasoline, diesel, and other petroleum products. Refiners in both countries have also benefited in recent years from increasing oil production within their borders. Growth in the Alberta oil sands in particular has given refineries in both Western and Eastern Canada increased access to domestically sourced bitumen and upgraded synthetic crude oil. Today, we continue our series on Canada’s refining sector with a look at the refineries in the eastern half of the nation, and their increasing use of Canadian oil.
In many ways, the natural gas shortages and price spikes that came with last week’s Deep Freeze had nothing at all to do with hydrogen. There were no “green” hydrogen plants that froze up in the cold, no withdrawals of stored hydrogen into distributed local fuel cells backing the power grid, no shortages of fuel for hydrogen vehicles. None of that occurred because hardly any of that infrastructure exists just yet. But that doesn’t mean there was no link between last week’s natural gas market and existing forms of hydrogen production, namely “gray” hydrogen used to produce ammonia, most of which is used in the manufacture of fertilizers, and which makes up about a quarter of the hydrogen market. In fact, there was a strong connection, one that highlights the flexibility of industrial natural gas use during price spikes and possibly exposes a vulnerability in gray hydrogen production. Today, we continue our series on hydrogen with a look at how the ammonia industry responded to the recent spike in natural gas prices.
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.
Here in Texas, the snow is melting, the power is back on, and some of us even have drinkable water. We’ll be dealing with the aftermath of the 2021 Deep Freeze for months, and talking about the insane natural gas and power prices for as long as gas and power markets exist. One thing you have not heard much about during these crazy few days is propane. And given what we’ve been through, no news is good news. Sure, it was impossible to exchange a tank at the local Quickie Mart, and there were sporadic reports of delayed propane deliveries and local shortfalls. But even up in the coldest Midwest states, there were no market meltdowns, no skyrocketing prices. Instead, propane has been the go-to fuel to keep folks warm, to get energy production moving again by defrosting wellheads and pipeline valves, and even to get restaurants back on their feet. It’s always dangerous to declare a winter victory with a few weeks left to go in the season, but today we’ll take that risk.
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.
Many of us need a break from natural gas market mayhem, rolling blackouts, and frozen pipes, so we’re turning to a very different topic — at least for a day. ESG, or more specifically the environmental part of the too-important-to-ignore environment/social/governmental movement. The fact is, for many investors, lenders, and others who give heavy weight to ESG in their decisions, the companies that produce, process, transport, refine, and/or export hydrocarbons are automatically suspect. At the same time, though, it is broadly understood that crude oil, natural gas, and NGLs remain essential commodities, and that it could take decades for economies around the globe to significantly reduce their dependence on them. So, where does that leave hydrocarbon-centric companies in 2021’s ESG-conscious world? Today, we continue our series on ESG issues and how they relate to players in the energy industry.
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.