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.
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When it comes to Texas natural gas markets, the Permian tends to steal the show. With its roughly 2 Bcf/d of annual production growth, constrained pipelines and absurdly cheap — sometimes even negative — pricing, it’s hard for the other gas hubs in the Lone Star State to garner much attention. However, the myopic focus on West Texas overlooks a noteworthy gas market shake-up taking place on the Texas Gulf Coast, where most of the Permian’s incremental gas production is headed and where multiple new liquefied natural gas facilities are coming online to move the new supplies into world markets. Also, new export pipelines are moving increasing volumes south of the border to Mexico. Today, we provide an update on the latest in Texas Gulf Coast gas infrastructure changes and their potential impacts on the region’s supply and demand balance.
It was reported earlier this month that Shell is seeking a buyer for its Washington state refinery, which is located just outside Seattle in Anacortes. That brings to eight the number of U.S. refineries said to be up for sale by a variety of sellers, from integrated major oil companies to independent merchant refiners — plus another refinery that is already under contract. That’s an unusually high number — refineries rarely change hands in the U.S. and when they do, it’s typically for large sums of money to sophisticated and vertically integrated buyers. Today, we discuss the facilities on the block in the East Coast and Mid-Continent regions and the market drivers that could be impacting the decisions of potential buyers and sellers.
The Denver-Julesburg Basin in northeastern Colorado and southeastern Wyoming has been producing crude oil for many decades now, but there were only a few crude gathering systems there until just the past three or four years, which were marked by a rapid ramp-up in production associated with the Shale Revolution. The development of these systems was spurred by producers’ desire to more efficiently and cost-effectively transport increasing volumes of crude from their new horizontal wells to new and expanded takeaway pipelines. The gathering systems have been built and added to over time by a combination of entities –– producers themselves, midstream affiliates of producers, and independent midstream companies, many of them backed by private equity. Today, we discuss highlights from our new Drill Down Report on D-J Basin crude oil gathering systems.
After a decade in which unprecedented upstream production growth triggered massive investment in infrastructure to get crude oil, natural gas and NGLs to market, 2020 is a major inflection point for the U.S. midstream industry. The good news is that after peaking at a whopping $37 billion in 2019, midstream capital expenditures are forecast to steeply decline over the next few years as the lion’s share of the infrastructure needed to gather, transport, process, and store current and expected hydrocarbon volumes has already been built or is nearing completion. And, despite continued cutbacks in capex by exploration and production companies, output is still forecast to rise in 2020, which should boost earnings growth for the midstream sector. But all midstream companies aren’t alike, and the prospects for individual entities vary widely because of the specific basins and hubs where they’ve decided to build, acquire, expand or divest. Today, we analyze the headwinds and tailwinds these companies will experience, and how their decisions over the past few years will help determine their prospects.
To say that Permian crude oil quality varies is an understatement at best. In fact, there’s as much variety in the crude coming out of West Texas as there is in the arsenal of a major league pitching ace. Handling those varied crude qualities is the challenge of midstream operators, who, like batters facing down a Randy Johnson or Pedro Martinez in their prime, need to do the best they can with what they’re given. With the start of spring training only a month away, we begin a series detailing the current mix of Permian crude oil qualities, how pipelines are handling them, and what it means for exports, the end destination for much of today’s incremental Permian oil production. Today, we discuss Permian crude quality variations and the steps new pipelines are taking to deal with it.
The rapid increase of natural gas processing capacity in the Bakken in recent months has helped to ease producers’ growing pains, clearing the way for more crude oil and associated gas to be produced there and more Bakken gas to flow into the Midwest. That good news is countered, however, by bad news for Western Canadian gas producers, whose long-standing pipeline takeaway constraints only worsen as more Bakken gas flows into the Northern Border pipeline that cuts through North Dakota on its way to Chicago and other downstream markets. Today, we continue our series on the fight between Bakken and Western Canadian producers for space on Northern Border with a look at incremental flows into that key pipe.
Transporting crude oil from the lease to refineries and export docks is like a long-distance relay race. The crude oil gathered from several wells is handed off to shuttle or takeaway pipelines, which then pass it on to regional crude hubs like Cushing, OK — from the hubs, crude is transferred to still other pipes. To get the relay going, the developers of crude gathering systems work closely with their takeaway pipeline counterparts to figure out the most efficient way to effect the first baton pass. Today, we continue our series on crude-related infrastructure in the Rockies’ Denver-Julesburg (D-J) Basin with a look at Outrigger Energy’s existing and planned gathering systems, and their connections to Tallgrass Energy’s still-expanding Pony Express takeaway pipeline.
After holding above $2/MMBtu in the first half of January, the CME/NYMEX February natural gas futures contract caved in this week, closing Tuesday and Wednesday at $1.895/MMBtu and $1.905/MMBtu, respectively. The last time we saw prices this low was in March 2016. But to see such levels trading in January, typically one of the coldest and highest-demand months of the year, you’d have to go back more than two decades — to 1999. Today, we explain the fundamentals behind the price collapse earlier this week and its implications for the 2020 gas market.
Fear about supply interruption isn’t the frantic force it used to be in the crude oil market. A deadly confrontation that might have pushed the U.S. and Iran to the verge of war raised the spot Brent crude oil price to above $70/bbl early in the week of January 6. Despite continuing regional concerns, the price quickly subsided. By January 13, Brent spot had fallen to $64.14/bbl, its lowest point since December 3. Before the Shale Era, a U.S.-Iranian face-off may well have launched Brent crude to well over $100/bbl as oil traders blew fuses over the heightened possibility of disruption to Persian Gulf oil production and transportation. There’s nothing like adequacy of supply, globally dispersed, to keep things calm — or at least calmer than they would have been if the U.S. and Iran had drawn so much sword a dozen years ago. In this blog, we’ll discuss where U.S. crude exports have been heading, how close the oil gets to strategically touchy areas, and whether the market still has reason to worry about disruption to oil supply.
Canadian oil and natural gas producers were dancing very much to the same tune as their U.S. counterparts in 2019: reduce capital spending, live within cash flow and improve returns to investors. The only major difference for Canadian gas producers is that they were forced to dance even faster due to abysmal natural gas pricing during the summer of 2019, which cast a very negative pall over the whole sector for the remainder of last year. Although the focus on spending restraint, cash flow and returns has not changed for these producers upon entering 2020, there are encouraging signals that Canadian gas pricing will be materially improved this year, especially during the summer months, supporting higher cash flows and a cautious expansion in capital spending. Today, we examine the drivers behind what might increase capital spending by gas producers and lead to an increase in supplies.
For a few years now, the Shale Revolution has been opening up development opportunities hardly anyone would have thought possible in the Pre-Shale Era. For example, new crude oil, natural gas and NGL pipelines from the Permian to the Gulf Coast, lots of new fractionators and steam crackers, as well as export terminals for crude, LNG, LPG, ethane and, most recently, ethylene. And here’s another. Thanks to the combination of NGL production growth and new ethylene supply — plus increasing demand for alkylate, an octane-boosting gasoline blendstock — the developer of a novel ethylene-to-alkylate project along the Houston Ship Channel has reached a Final Investment Decision (FID). Today, we discuss how the FID is driven by both supply-side and demand-side trends in the NGL and fuels markets.
Tallgrass Energy’s Rockies Express Pipeline (REX) has been through a lot in its 10-plus years of operation. Since its first eastbound-only segments started moving natural gas out of the Rockies in 2008, flows on the pipeline have evolved due to market events, primarily the onset of the Shale Revolution, which has resulted in a surge of gas supplies in the Eastern U.S. and increasing gas-on-gas competition across North America. Rising to the challenge, REX has undergone a number of transformations to adapt to the shifting gas flow patterns and price relationships, including reversing flows on the eastern zone of the pipe to move gas west from Ohio. In 2019, REX was again put to the test, this time on the western end of the pipe, where the bulk of its legacy long-term contracts for eastbound flows out of the Rockies expired, with the last of them rolling off on November 11, 2019. Some of that has since been recontracted, and the in-service of the REX Cheyenne Hub Enhancement and Cheyenne Connector projects could further shore up REX mainline flows. Today, we begin a short series providing an update on REX’s eastbound gas flows and contract changes.
Texas consumes far more diesel fuel than any other state and almost as much gasoline as car-crazy California, which also has 10 million more people. The long-distance distribution of refined products within the Lone Star State is handled largely by tanker trucks, but in the past couple of years, midstream companies have been adding a lot of new refined products pipeline capacity, not just to help deliver diesel and gasoline within Texas — including the diesel-hungry Permian Basin — but also to move motor fuels to the Mexican border for export. And more diesel and gasoline pipe capacity is on the way. Today, we discuss the new and expanded refined products pipelines criss-crossing Texas.
Occidental Petroleum’s recent acquisition of Anadarko Petroleum made Oxy the #1 producer in the Denver-Julesburg (D-J) Basin and gave it a majority stake in Western Midstream Partners, which owns crude-gathering and other midstream assets in the D-J, the Permian and the Marcellus. While Western Midstream’s gathering focus had been on helping Anadarko meet its own midstream needs, Oxy sees the partnership taking on a broader role as a provider of gathering services to third parties as well. Toward that end, Oxy and Western Midstream a few days ago announced a series of agreements designed to allow Western Midstream to operate as an independent company. Today, we continue a series on crude-related infrastructure in the D-J with a look at Western Midstream’s gathering and related assets owned in part by the basin’s largest oil, natural gas and NGL producer.
This year looks like it could be a better one for many Canadian natural gas producers. Like their brethren in the U.S., they have been forced in recent years to increasingly spend within — and even less than — cash flow as other sources of financing have dried up and investors have prioritized better returns over production volume growth. With Canadian gas producers having also faced some of the worst natural gas pricing conditions on record in 2019, far worse than those in the U.S., it is no wonder that Canadian natural gas supplies pulled back in 2019, marking the first down year for overall gas supplies since 2012. Despite what is likely still to be a cash flow and spending constrained environment in 2020, there is the potential for real upside for Western Canadian natural gas supplies this year, especially for the supply that flows into TC Energy’s Nova pipeline system. Today, we consider what may be setting the stage for gas supply gains on the Nova system in 2020 after a somewhat dismal 2019.