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.
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.
The natural gas market dynamics that were expected to turn gas flow patterns and price relationships in the Eastern U.S. on their heads and, in turn, transform supply-demand dynamics in Louisiana — including around the U.S. price benchmark Henry Hub — have come to fruition. LNG exports have surged as new liquefaction and export terminals have come online, injecting a new demand source along the Louisiana coastline. Producers have lined up to serve that demand. And midstreamers have worked to get the gas there, reversing and expanding existing northbound pipelines to move gas south into and through the Bayou State. Now, Louisiana’s gas market is nearing a critical juncture: the pipelines that connect the supply gateways in northern Louisiana to the demand centers along the Gulf Coast are nearing saturation. Today, we begin a series providing an update on Louisiana’s gas pipeline constraints and the projects lining up to alleviate them.
New U.S. liquefaction trains and export terminals have added LNG to an oversupplied global market. International gas prices are at their lowest levels in several years, price spreads between the U.S. and destination markets have collapsed and — to make matters even worse — a coronavirus pandemic threatens to undermine LNG demand growth. U.S. LNG exports nevertheless have been increasing with each new liquefaction train that comes onstream, though, mostly because their long-term offtake contracts make cargo liftings relatively insensitive to global prices. The question is, will dire global market conditions somehow undo U.S. LNG production growth? Today, we discuss highlights from our new Drill Down Report on the future of U.S. LNG exports.
Unlike most natural gas producing jurisdictions in North America facing a pullback in drilling and capital spending, producers in Western Canada appear to be doing the opposite and lining up for a year of rising production, higher average prices and additional pipeline capacity from producing basins. In short, 2020 should be a year in which supplies in the region mount a comeback after the dismal down year for supplies — and prices — that characterized 2019. A good part of that supply and pipeline capacity growth optimism has to do with a major pipeline expansion out of the Montney Basin in northeastern British Columbia that just recently entered service. Dubbed the North Montney Mainline and operated by Canada’s largest gas pipeline company, TC Energy, this vital piece of new pipeline egress from one of the most prolific unconventional gas basins in North America is setting up Western Canadian gas supplies for recovery in 2020 and beyond. Today, we continue our series with a look at what this may portend for gas supplies this year.
Given that Permian natural gas prices are once again hovering under $0.50/MMBtu, Texas’s other gas markets get little attention these days. That doesn’t mean that major shifts in the Lone Star State’s natural gas supply and demand markets aren’t occurring outside of West Texas, however. In fact, it’s quite the contrary, particularly when it comes to the Houston Ship Channel gas market. There, major changes — new gas pipelines, pipeline reversals and new LNG trains — continue to influence flows and prices. Today, we provide an update on the latest in gas infrastructure changes along the Texas coast and their potential impacts on the region’s supply and demand balance.
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.
After a major decontracting and partial recontracting last fall, Tallgrass Energy’s Rockies Express Pipeline headed into 2020 with 839 MMcf/d in firm, long-haul commitments for natural gas moving east out of the Rockies for delivery into the Midwest. That volume is down from 1.3-1.8 MMcf/d in firm commitments previously. The contracted volume is also much lower than the peak — and even the average — historical gas flows on the route to the Midwest markets in recent years. At the same time, Tallgrass’s Cheyenne Connector pipeline and Cheyenne Hub Enhancement projects are expected to bring as much as 800 MMcf/d of new firm gas supply from the Denver-Julesburg (D-J) Basin to the REX mainline at Cheyenne Hub. What will these changes mean for Rockies’ eastbound flows and prices? Today, we wrap up our series on REX’s recontracting with an assessment of how the recent contract changes could affect REX gas flows.
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.
Natural gas supplies in Western Canada fell into a hole in 2019, registering their first decline in a half-dozen years. That drop was led by a supply pullback on TC Energy’s Nova Gas Transmission Limited (NGTL) system, the largest gas pipeline network in the region, as producers grappled with widespread pipeline maintenance, shrinking budgets, and wellhead shut-ins due to ultra-low prices, especially during the summer months. That supply hole is going to be fixed in the months ahead, thanks to a major pipeline expansion — the North Montney Mainline — that recently entered service with a direct connection into the NGTL system. With this new pipeline tapping deeper into the vast Montney formation in northeastern British Columbia, gas supplies are showing signs of pushing higher, and more upside is expected in the months ahead. Today, we examine the new pipe and what it means for gas supplies on NGTL.
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.
The Shale Revolution created enormous opportunities for U.S. midstream companies. But opportunities are only that. It’s what individual midstreamers did with those opportunities through the 2010s — the decisions each made on where to invest and what to invest in — that will help determine how well they will do over the next decade and beyond. And the best way to assess the wisdom of these investments is to examine them one by one, and consider their locations, their exposure to risk and their potential for growth. Today, we discuss highlights from the newly released company-by-company portion of East Daley Capital’s “Dirty Little Secrets” report.
For much of the time since it began operations, the capacity on Tallgrass Energy’s Rockies Express Pipeline has been contracted and utilized at high rates for long-haul flows east from the Rockies to the Midwest. Specifically, the pipeline consistently has had between 1.3 and 1.8 Bcf/d out of a total 1.8 Bcf/d contracted, mostly for 10-year terms. That all changed in the past year, however, as the original long-term shipper contracts that took effect in 2009 came due and the pipeline experienced a major decontracting, with the bulk of the contracts rolling off in November 2019. Since then, a number of open seasons led to a partial recontracting. Tallgrass also is developing two projects — Cheyenne Connector and REX Cheyenne Hub Enhancement — that could increase flows to REX later this year. Today, we continue a series providing an update on eastbound pipeline contracts and gas flows on REX.
The development of Appalachia’s Marcellus and Utica shales has flipped regional natural gas prices in the U.S. Northeast from their long-time premiums to Henry Hub, to trading at a significant discount and, in the process, reversed inbound gas flows, including from Eastern Canada. But there is an exception: from an entry point at the northern edge of New York, the Iroquois Gas Transmission pipeline is still importing Canadian gas supply nearly year-round to help meet local demand, despite its proximity to Marcellus/Utica production via other Northeast pipelines. This has kept prices along the Iroquois pipeline system at a premium to the other points in the region. And with the new, 1,100-MW Cricket Valley Energy Center power plant due online this spring, Iroquois prices are likely to strengthen. Today, we examine the dynamics driving Iroquois prices and gas flows.