In its landmark West Virginia v. EPA decision, the Supreme Court on Thursday scaled back the powers of the Environmental Protection Agency — and, it would seem, other federal administrative agencies — to implement regulations that extend beyond what Congress specifically directed in its authorizing legislation, in this case the Clean Air Act. The ruling didn’t go as far as throwing out the long-standing deference of courts to federal agencies’ interpretations when it comes to acting under statutory law where there’s any ambiguity — the so-called “Chevron Deference” doctrine. But it does impose a threshold roadblock to the use of the doctrine, based on the “Major Question” doctrine. Yep, we have a duel of the doctrines here. The end result here is to hamstring the EPA and the Biden administration from reinstating emissions-limiting rules similar to the ones the Obama EPA put forth a few years ago in the “Clean Power Plan,” at least not without legislative approval. Most of the oil and gas industry and a lot of the power industry are likely to welcome the check on this particular regulatory authority, and certainly most of the oil and gas industry welcomes some restraint on the EPA in general. However, the broader implications of the ruling could make life more difficult in the near-term for industries like oil and gas that rely on a stable, or at least semi-predictable, regulatory environment for making long-term plans. In today’s RBN blog, we explain what was at stake in this case and what the decision could mean for the oil and gas industry.
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Over the past five years, the production of natural gas liquids from gas processing plants has soared by almost 2 million barrels per day (2 MMb/d), or about 60%. That has been great news for natural gas producers, processors, and end-use markets. But there is a catch: the rate of production does not match up with demand. While production is a steady, “ratable” volume, demand is anything but ratable. Demand swings with the gasoline blending season, cold weather (or lack thereof) in the propane market, export demand, petchem feedstock economics, the impact of COVID-19 on transportation fuels, and a myriad of other factors. The flywheel that balances supply and demand on any given day is storage. Not just any storage, though. For NGLs, storage of large volumes means salt caverns. Huge caverns thousands of feet below the surface. Today, we update one of RBN’s Greatest Hits blogs and take a deep dive into the history of NGL storage — all the way back to Smoky Billue.
The Ridley Island Propane Export Terminal — Canada’s first propane export facility — has been a game changer since it started up in May 2019. Located along the coast of British Columbia, RIPET has been shipping record amounts of propane to Asian markets in recent months, just as Western Canadian propane production has been sagging due to the twin pressures of crude oil price weakness and COVID-19-related disruptions. With production down, RIPET gradually ramping up its export capacity, a second export terminal poised to come online nearby, and Canadian demand for propane holding steady, something has to give, right? Today, we examine the changing supply/demand outlook for Western Canadian propane, and what it might mean for railed exports to the U.S.
Propane exports from AltaGas and Vopak’s Ridley Island Propane Export Terminal on the west coast of British Columbia jumped to 52 Mb/d in May, the highest since it began operations in May 2019 and exceeding the terminal’s original design capacity for the second time this year. The increased exports suggest expanded capacity at the facility and the potential for sustained higher exports from there even as Western Canada’s propane supplies plateaued in 2019 and then were hammered lower earlier this year as oil prices and demand collapsed. The resulting tighter balance in the greater Pacific Northwest region has boosted prices there, wreaking havoc on price spreads and disrupting rail movements to U.S. destinations that have relied on them for the past few years, from the Midwest to California. Moreover, Western Canadian export capacity is poised to nearly double by next spring, when a second nearby export terminal is slated to begin operations. With supply upside looking tenuous, but overseas exports set to rise further in early 2021, there is a serious squeeze emerging for propane rail exports to the U.S. Today, we consider the implications of what could be a much tighter propane market in Western Canada over the next few years.
Since the mid-2010s, MPLX has been developing a far-reaching pipeline system for delivering heavier natural gas liquids and field condensate from the Utica and “wet” Marcellus plays to Midwest refineries for gasoline blending and refining, and to the Alberta oil sands for use as diluent. The multi-year, multi-project effort, which has involved the construction of new pipelines, the repurposing of existing pipes, and the development of new storage capacity, will reach another milestone next month, when MPLX starts batching normal butane and isobutane through most of the pipeline system. And further enhancements are on the horizon. Today, we provide an update on the master limited partnership’s long-running strategy for moving Marcellus/Utica-sourced liquids to market more efficiently and at a lower per-barrel cost.
Energy markets balance — eventually. In the midst of the turmoil we’ve experienced this year, there have been periods when it seemed like markets were going to hit the wall. But even with the historic WTI oil price glitch on April 20, the physical crude oil markets continued to function. That’s the way it is supposed to work, and it’s good news. The bad news is that figuring out how these markets are balancing in these volatile conditions can be challenging if not downright perplexing. Nowhere is that more true than the market for U.S. propane. Production is down, but so is demand. Inventories are up, and so are prices. Propane continues to be exported, even though global demand has been whacked by COVID. In today’s blog, we explore these developments and put the spotlight on RBN’s NGL Voyager, our subscriber report and data service that we have just reformatted, upgraded and generally reconstructed to meet the information needs of today’s NGL marketplace.
The Marcellus/Utica production region in the northeastern U.S. is not immune to the upheaval in global energy markets. There, a number of E&Ps are implementing further cutbacks in their natural gas production. That will result in lower NGL production, which may have serious implications for regional supplies of propane for heating this coming winter. LPG exports out of the Marcus Hook terminal near Philadelphia also may be impacted. Today, we look at recent developments in the Marcellus/Utica and the potential effects of lower NGL production in the region.
During the last two weeks of April, a barrel of propane in Mont Belvieu was more expensive than a barrel of WTI crude oil in Cushing. That’s never happened before. You might think that such an aberration could be blamed on the wacky April-May 2020 COVID crude market, but that is only part of the story. Propane production is falling and pre-COVID projections of continued supply growth are out the window. But new gas processing plants, pipelines, fractionation facilities, dock capacity and downstream demand have come online in recent years, in anticipation of those ill-fated additional supplies. Already we are seeing flows, price relationships and differentials convulsing in response to the new reality, and projections of future supply/demand imbalances suggest a previously unthinkable possibility: a market that can’t get enough propane supply, especially if the winter of 2020-21 is a cold one. In today’s blog, we will explore the evidence of these market developments that is already visible and look to what may be ahead for propane supply and demand.
The crude oil market garners all the headlines in the COVID/OPEC+ era, and understandably so. But the NGL market is also in turmoil and deserves attention too. Declining volumes of associated gas from crude-focused plays will soon be cutting into NGL supplies. Demand for natural gasoline has been hit hard, along with the crude, motor gasoline and jet fuel markets. But propane prices relative to crude oil have soared to historically high ratios, in part reflecting recent strong international demand for U.S. LPG exports. As for ethane — the lightest NGL, and the most important feedstock for the Gulf Coast petchem sector — it is going through wrenching changes, with major implications for both suppliers and steam crackers. Today, we begin a short series on the major dislocations that crude-market chaos is spurring in NGL production, ethane rejection, feedstock selection by steam crackers, and ethane/LPG exports.
If Saudi Arabia and Russia flood the world with their crude oil in the midst of a global demand crisis, it would have impacts and implications far beyond crude. A ramp-up in Saudi and Russian oil production this spring would also increase their output of associated gas and NGLs. At the same time, the opposite will be happening in the Permian and other liquids-rich U.S. shale plays, where producers, stunned by sub-$25/bbl oil prices, already are pulling back on drilling and later this year will see their oil and NGL production gradually level off and eventually decline. All this is already turning the international LPG market on its head — just last week, U.S. propane exports plummeted by nearly 40% versus the prior week, to only 889 Mb/d. Today, we consider recent extraordinary market developments and their effect on the arb between Mont Belvieu and Far East LPG prices.
The collapse in crude oil prices has sent shock waves throughout the global energy industry and Canada has been no exception. Sorting through all the impacts will take time, but what’s clear is that any earlier optimism surrounding supply growth in Canada has evaporated, including for propane supply to feed the new propane export terminals on British Columbia’s coastline. Edmonton propane prices fell 58% since the start of March to as low as 10.25 cents per gallon in U.S. dollars on March 23 — the lowest level since April 2016 — and settled yesterday at 13.13 cents per gallon, according to data from our friends at OPIS. A dampened supply outlook means future export expansion plans also are being reconsidered. Today, we explore what the sharp decline in propane prices could mean for the region’s supplies and future propane exports, including from Pembina Pipeline’s nearly completed export terminal in Prince Rupert, BC.
Canada has been facing a similar situation to the U.S. in recent years in which the production of natural gas liquids, such as propane, has been rising sharply thanks to a focus on liquids-rich gas wells in unconventional gas plays. In response to the rising bounty of propane, infrastructure development in Canada has focused on export projects, and in 2019, the completion of the new Ridley Island Propane Export Terminal in British Columbia enabled the first overseas exports of propane from Canada’s west coast, allowing Western Canadian producers to access destination markets beyond just the U.S. for the first time. Later this year, Pembina Pipelines, a developer of energy infrastructure projects across Western Canada, will complete a new propane export terminal just outside Prince Rupert, BC, further boosting propane exports to overseas markets. Today, we take a closer look at propane supply issues, Pembina’s new propane export terminal and recently announced plans to further expand the terminal’s export capacity.
It’s almost Spring 2020 and energy markets are making another turn. Prices have been clobbered by a combination of low, weather-related demand and COVID-19. Tight capital markets have the E&P sector hunkered down and the pace of production growth is slowing. But at the same time, new pipelines out of the Permian and Bakken are under construction; some are already ramping up flows. Long-delayed LNG terminals and NGL-consuming petrochemical plants are coming online. Essentially all growth in crude and gas — plus most incremental NGL production — is being exported to global markets, and those markets are pushing back. All this has huge implications for commodity flows, infrastructure utilization and price relationships for oil, natural gas and NGLs. Which means that it’s time for RBN’s School of Energy, with all of our curriculum and models updated for the realities of today’s energy markets. Today — in a blatant advertorial — we’ll examine our upcoming School of Energy and explain why this time around we are concentrating even more than usual on NGLs.
There is no such thing as a typical NGL barrel. For example, the composition of y-grade production out of the Marcellus is significantly different from y-grade out of most of the Permian. And it is not just gas processing engineers who care. The make-up of an NGL barrel is inextricably linked to the value of that barrel. The reason is pretty simple: there’s a big difference in the value of each of the five NGL products. These days, natural gasoline is worth nearly eight times as much per gallon as ethane. Normal butane is worth 1.6X as much as propane. Consequently, the more natural gasoline and normal butane in your barrel versus the amounts of ethane and propane, the more the barrel is worth. So it’s important to anyone trying to follow the value added by gas processing and related infrastructure to understand where these numbers come from and how much the composition of a barrel can vary from basin to basin, or for that matter, from well to well. In Part 2 of our series on gas processing, we turn our attention to the variability in the mix of NGL production and its implication for processing uplift.
Wouldn’t it be nice if everything you needed to keep up with the market was right there on your phone or tablet? And it would be even handier if the data and stories organized themselves just for you, around topics you care about the most. Such a technology would address a formidable challenge we all face: keeping up with the torrent of market information coming at us from trading platforms, online services, trade publications, you name it. It would pull everything you needed into a single database and then organize information on the fly around whatever topic matters most to you at a point in time. And it would be able to reorganize that information on demand as market data ebbs and flows. Over the past few months, we’ve designed an app that tackles this challenge head-on. Today we are introducing the concept of ClusterX, explaining how it works, and giving you the opportunity to help us roll out our new technology to the RBN blogosphere. Warning: this is a blatant advertorial for our new energy market analytics app.
OK, we admit it. Our title may be a bit of an overstatement in early 2020, but it was absolutely true back in 2012, when the frac spread was $13/MMBtu. These days, the frac spread — the differential between the price of natural gas and the weighted average price of a typical barrel of NGLs on a dollars-per-Btu basis — is only $2.48/MMBtu as of yesterday. But with Henry Hub natural gas prices in the doghouse — they closed on February 11 at $1.79/MMBtu — getting $4.27/MMBtu for the NGLs extracted from that gas, or an uplift of 2.4x, is still a pretty darned good deal. And that’s Henry Hub. Natural gas prices are lower in all of the producing basins, and are likely headed back below zero in the Permian this summer. So even with NGL prices averaging 30% lower than last year, the value of NGLs relative to gas can be a big contributor to a producer’s bottom line — assuming, of course, that the producer has the contractual right to keep that uplift. Today, we begin a blog series to examine the value created by extracting NGLs from wellhead gas, including processing costs, transportation, fractionation, ethane rejection, margins, netbacks and the myriad of factors that make NGL markets tick. We will start with the frac spread — what it tells us in its simplest form, how we can improve the calculations so it can tell us more, and, just as important, the economic factors that the frac spread excludes.