Lower crude oil prices whack oil-directed drilling, slashing crude production, which cuts associated gas output, tightening the gas supply-demand balance, and boosting gas prices enough to spur more gas-directed drilling — it’s a classic case of commodity market schadenfreude, where one product benefits at the expense of another. That’s the way it was supposed to work, according to various trading strategies touted a few weeks back. But here we sit, with crude oil prices still around $40/bbl and gas prices languishing at a paltry $1.66/MMBtu. Was there something wrong with the schadenfreude thesis, or do we have to look deeper to understand how prices will behave in this convoluted COVID era? In today’s blog, we’ll explore this question and what it may mean for natural gas prices in the coming months.
Posts from Rusty Braziel
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.
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.
In an energy market filled with incalculable uncertainty, it is no surprise that most of the focus is on the short term: production shut-ins, collapsing demand, refinery unit shutdowns, ballooning storage inventories and continually weakening prices. But even in the face of such dire circumstances in the weeks just ahead, there remains a cautious optimism — relatively speaking — for the resumption of some kind of new normal on the other side of COVID. You can see that expectation in the numbers, with the WTI May 2020 contract settling on Friday at $18.27/bbl, but the May 2021 contract up to $35.52/bbl. Granted, that May 2021 price would have been catastrophic if viewed in January 2020, but now it’s a bullish 95% increase over the front month. It is that shift in perspective that underlies the fundamentals content that we developed for our two-day Spring 2020 Virtual School of Energy, held last week in the cloud: how things were viewed BEFORE the meltdown, and how things look AFTER — over the next five years. Did you miss the conference? Not to worry. The entire 14 hours of content are available online in our encore edition. It’s almost like being there! Today’s advertorial blog reviews some of the most important findings we covered at School of Energy and summarizes our overall virtual conference curriculum.
Energy markets are changing faster than at any time in history. It’s hard enough just to keep up with what’s happening today, much less try to anticipate what’s ahead on the other side of COVID. But that’s exactly what we’ll be doing next week at RBN’s Virtual School of Energy. More than one-third of the curriculum is a detailed review of RBN’s hot-off-the-presses forecasts for all the essential elements of U.S. crude oil, natural gas and NGL markets, including our freshly updated outlooks for production, infrastructure utilization, exports/imports and demand. Better yet, we’ll put these forecasts in the context of our fundamental analysis and models, so you can not only understand where it looks like we’re headed today, but gain the skills to adjust your outlook on the fly as circumstances change. Although this blog is an advertorial, stick with us if you would like to know more about how the RBN crystal ball works.
Like everything else in the world, energy markets are undergoing totally unprecedented convulsions. It seems as if everything that was working before COVID-19 is now broken, and an entirely new rulebook has been thrust upon us. Of course, it is impossible to know how crude oil, natural gas and NGL markets will play out over the next few weeks, much less in the coming years. But if we make a few reasonable assumptions, extrapolate from what we know so far, and crunch through a bit of fundamental analysis, it is possible to imagine what energy markets will look like after the worst of the coronavirus pandemic is behind us. One thing is for sure: things will not be anything like they were before. Where energy markets may be headed next is what we will conjure up in today’s blog.
Statewide shelter-in-place orders, worldwide business shutdowns, market meltdowns, medical calamities. Much of what is going on right now is unprecedented in the modern era, and there are no guideposts to help predict what happens next to the world as we knew it. But in the boom-bust energy sector, it is déjà vu all over again. We have seen steep drops in prices, drilling activity and production enough times to have some idea about how this is likely to play out. Granted, this time around it is particularly bad, but that doesn’t change the sequence of events that we are likely to experience over the coming months and years. Today, we’ll look back at what happens to Shale-Era basins after a price collapse, focusing on the inherent lag between a major reduction in activity level and the inevitable production response.
Throw out your old production forecasts. Delete your pricing model spreadsheets. Push out the dates on your infrastructure project timelines. Or kill the projects all together. We’ve got a black swan on our hands here, folks. Perhaps a flock of black swans. And while we may see something like normal again in a few months, there is little doubt that it will be an entirely new normal. How do we even think through the wrenching transformations that are working through energy markets? At RBN, we don’t have any more answers than anyone else, but we do have a structured approach to market analysis supported by a set of spreadsheet models that are the core of our School of Energy, scheduled for April 14-15. We think that’s exactly the kind of approach necessary to make sense out of this volatile and chaotic market. And although we have cancelled the in-person conference, we’ve made the decision to GO VIRTUAL! Today, we explain our decision to move forward with the virtual School of Energy and discuss the new material we are incorporating into the curriculum to address today’s market realities.
On Friday, global energy markets entered uncharted territory. Already facing declining demand due to the impact of COVID-19, markets then were dealt a body blow with the collapse of the OPEC-Plus alliance and the resulting prospect of a significant increase in supply. Saudi Arabia wanted to manage supply to balance against lower demand, but Russia was having none of it. Instead, reports from the OPEC-Plus meeting indicate that Vladimir Putin has declared war on U.S. shale. Then on Saturday, the plot thickened. Saudi Arabia made huge cuts in the price of its crude oil, presumably in a high-stakes move to bring Russia back to the negotiating table. Even though we are witnessing unprecedented market conditions, it’s not Armageddon. Crude oil will continue to be pumped, piped, shipped and refined. Most infrastructure projects under construction before the collapse in oil prices will be completed. The big question is, how will the market adapt? In today’s blog, we’ll begin an exploration of that question.
On Friday, CME/NYMEX WTI Cushing crude oil for April delivery closed at $44.76/bbl, down more than $16/bbl, or about 27%, since New Year’s Day. The declines in natural gas and NGL prices were not quite as severe, but only because those commodities were hit harder than crude during 2019. Even before COVID-19 landed on the market, energy prices were already under pressure from continued record production levels from U.S. shale, weakening demand, a mostly mild winter and a general investor pall over all things carbon. The threat of a global coronavirus pandemic was all it took to push things over the edge. So now what? Of course, nobody knows. But we can contemplate what this all could mean for energy markets, based on what we’ve seen in recent market statistics and price behavior. So that’s what we’ll do in today’s blog.
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.
For the first time since late September 2013, the ratio of crude oil to natural gas (CME/NYMEX) futures on Friday hit 30X. That means the price of crude oil in $/bbl was 30 times the price of natural gas in $/MMBtu. Such a wide disparity in the value of the liquid hydrocarbon versus the gaseous hydrocarbon has huge implications for where producers will be drilling, the proportion of associated and wet gas that will be produced, the outlook for NGL production, and a host of other energy market developments. The ratio has been moving higher for the past couple of years, and recently has been boosted by the combined impact of increased tension in the Middle East (higher oil prices) and a warm winter so far in many of the largest gas-burning population centers in the U.S (lower gas prices). But it’s pretty likely that the trend will be with us for the long term. So today, we’ll begin a series that looks at the implications of this price relationship.