The battle over the future of Enbridge’s Line 5 light crude oil pipeline through Michigan is heating up. In recent weeks, Michigan’s new attorney general filed suit to throw out the 1953 easement the state granted to allow the pipeline to be laid under the Straits of Mackinac — the narrow waterway between Michigan’s upper and lower peninsulas — and to block implementation of an agreement Enbridge and the state’s then-governor reached last fall to replace the section of Line 5 under the straits by the mid-2020s. Enbridge is pressing ahead, maintaining that the existing pipeline is safe and the 2018 agreement is legal and fully enforceable. All that raises two questions: just how important is Line 5 to the Michigan and Eastern Canadian refineries, and what would those refineries do if the pipeline were to cease operations? Today, we discuss recent developments and examine the issues at hand.
Daily energy Posts
U.S. ethane exports have risen steadily over the past five years, from next to nothing in early 2014 to an average of 255 Mb/d in 2018 and 269 Mb/d in the first three months of this year. But unlike its heavier NGL siblings propane and butane, which are in demand globally as fuels and feedstocks, ethane’s only established use is in steam crackers specifically equipped to process it, so there are only a few countries where exported ethane is likely to end up. Also, the waterborne transport of ethane is generally limited to specially designed ethane carriers, and there aren’t many of those around because of ethane’s restricted market. All this makes for an export commodity that stands apart. Today, we review the evolution of U.S. ethane exports and the challenges to export growth posed by the U.S./China trade war.
The Northeast natural gas market turned a new leaf in 2018, when takeaway pipeline capacity to move supply out of the Marcellus/Utica producing region finally caught up to — and even began outpacing — production growth. More than 4 Bcf/d of takeaway expansions entered service in 2018. Prices at the region’s Dominion South supply hub improved relative to Henry Hub and other downstream markets. And for the first time in years, Appalachian gas producers and marketers caught a glimpse of what an unconstrained, balanced market driven by market economics (as opposed to transportation constraints) could look like. 2019 will be the first full year of operation for many of those takeaway expansions that came online in 2018. Northeast production growth flattened through the first few months of 2019, but has ticked up in the past couple of months, albeit modestly, and the slate of future takeaway expansion projects has shrunk to just a couple stalled projects. Where does that leave capacity utilization out of the region this summer, and how long will it be before production growth hits the capacity wall again? Today, we begin a series providing an update on the Northeast gas market and prospects for balancing takeaway capacity with production growth.
By their very nature, crude oil gathering systems in the Permian are works in progress. They often start out small, serving only a few wells owned by a single producer — or maybe two or three. Over time, the systems typically branch out to serve more producers and more wells, and they add capacity as drilling activity picks up. Sometimes, they evolve into much larger systems with multiple gathering hubs and regional transport pipelines that shuttle large volumes of gathered crude long distances to big marketing hubs like Crane, TX, and Midland, where the oil can flow into any number of takeaway pipelines to Cushing or the Gulf Coast. Today, we continue our series on Permian crude gathering systems with a look at Oryx Midstream’s 860-mile gathering and regional transport network in the super-hot Delaware Basin.
Global demand for propylene is rising, but lighter crude slates at U.S. refineries and the use of more ethane at U.S. (and overseas) steam crackers has reduced propylene production from these plants. That has led to the development of more “on-purpose” propylene production facilities — especially propane dehydrogenation (PDH) plants — in both the U.S. and Canada. More than 2 million metric tons/year of new PDH capacity has come online in North America since 2010, another 1.6 MMtpa is under development, and propane/propylene economics may well support still more capacity being built by the mid-2020s, maintaining the U.S. and Canada’s position as propylene and propylene-derivative exporters. Today, we begin a series looking at “on-purpose” production of propylene by PDH plants and what the development of these facilities will mean for U.S., Canadian and overseas markets.
U.S. oil and gas producer share prices got a nice boost in mid-April from the Chevron/Occidental Petroleum bidding war for Anadarko Petroleum, which sold for more than a 40% premium to its price before Chevron’s opening bid. But the optimism was only temporary; the S&P E&P stock index has since retreated 13% to mid-February levels, during a month in which companies released their first quarter 2019 earnings reports. That suggests that, despite a 38% quarter-on-quarter increase in the pre-tax operating profit of the 44 E&Ps we track, investors found nothing in the first quarter results to dispel the generally negative sentiment that has hung like a dark cloud over the oil and gas industry since late 2014. Today, we analyze the first quarter financial performance of our 44 E&Ps and review the outlook for an industry ripe for further consolidation because of depressed equity valuations.
Refineries in Washington state have been reliable buyers of Bakken-sourced crude oil during the Shale Era, receiving an average of about 145 Mb/d — all of it by rail — over the past two-plus years. But a newly approved Washington law slashing the allowable vapor pressure limit for crude being unloaded from rail tank cars could hinder future growth in crude-by-rail shipments from North Dakota to the Evergreen State, or force Bakken producers to remove more butane and other “light ends” from the crude oil they rail west. It’s such a big deal that the state of North Dakota has indicated it will file suit to kill the new law. Today, we discuss Washington’s new law and its potential effects on Bakken crude oil producers.
There’s never a dull moment in the Permian gas market these days, as prices at the major trading hubs remain extremely volatile, fueled by insufficient natural gas pipeline takeaway capacity. After prices tumbled to fresh lows in late April, with the Waha hub trading as much as $9/MMBtu below zero, the market appeared to regain its footing somewhat in early May as production curtailments lifted prices above zero. However, that reprieve was short-lived; prices last week again fell into negative territory heading into Memorial Day weekend. That said, the possibility of new takeaway capacity materializing in the weeks ahead, earlier than expected, has renewed hope among some market participants that the Permian gas price woes will soon be a thing of the past. How likely is that really, and will it be enough to equalize the beleaguered market? Today, we look at potential near-term developments that could support Permian gas prices.
On its surface, the development of small-diameter crude oil gathering pipeline systems in the Permian may seem like a ho-hum topic. In fact, though, these systems are at the heart of critically important strategies to ensure the reliable, low-cost flow of crude to multiple takeaway pipelines out of the basin, and thereby enhance the oil’s value and minimize financial risk. A case in point is the 50-mile-plus, 100-Mb/d-capacity gathering system that a producer/midstreamer joint venture has been building in the Delaware Basin along the Texas/New Mexico line. Today, we continue our series on Permian gathering systems with a look at WPX Energy and Howard Energy Partners’ new pipes in New Mexico’s Eddy County and Texas’s Loving and Reeves counties.
It’s impossible to know for certain what will happen next in the international markets for propane, butane and ethane — there are too many variables and vagaries. What is very doable, though, is to gain a better understanding of the broader market forces at play. For example, the U.S. now has a few years under its belt as a major propane exporter, so it’s feasible to assess trends in where that propane is going — or no longer going — and to examine how propane exports to various parts of the world are impacted by everything from a high-stakes trade war to governmental efforts to encourage the use of cleaner cooking fuel. Today, we continue our deep-dive into propane, butane and ethane exports with a look at where propane exports from the U.S. East, West and Gulf coasts are heading, and why.
As Western Canadian natural gas production has been recovering off lows from a few years ago and pushing higher, one of the by-products of this recovery has been steadily rising production of natural gasoline, an NGL “purity product’ also known as plant condensate. Condensate production has been growing so much that Pembina Pipeline Corp. — a leading transporter of natural gasoline in the region — has been undertaking another round of expansions to its Peace Pipeline system to move more of the product to the Alberta oil sands. There, condensate is used as a diluent to allow the transportation of viscous bitumen to far-away markets via pipelines or rail. Today, we take a closer look at Pembina’s effort to expand the Peace Pipeline.
When it comes to getting crude oil to market, bottlenecks have always existed. Back in 2013-15, producers and shippers in the Rockies faced a serious lack of takeaway options. Midstreamers saw the problem and the money to be made, and quickly built more crude-by-rail capacity — and, over time, pipeline capacity — to fix things. Recently, major takeaway constraints emerged in the Permian, much to the detriment of netbacks at the wellhead. There was real concern for a few months that some producers might need to shut in production as there wasn’t any way to get incremental barrels out of the basin. Again, traders and midstream operators got savvy, restarted some dormant crude-by-rail options, initiated long-haul trucking out of Midland, and added more pipe capacity. But what if the next big bottleneck isn’t between two land-based trading hubs? What if there’s not enough export capacity at terminals along the Gulf Coast, the gateway to international markets? In today’s blog, we examine recent export and production trends, and discuss what those could mean for export infrastructure and logistics over the next five years.
This blog is based on research from Morningstar Commodities. A copy of the original report is available here.
U.S. crude exports out of the Gulf Coast averaged more than 2.4 MMb/d in the first four months of 2019 — using infrastructure that is increasingly constrained by a lack of deepwater ports. U.S. crude is reaching destinations worldwide, with large volumes traveling long distances to Asia on gargantuan 2-MMbbl vessels — Very Large Crude Carriers (VLCCs) — loaded offshore by ship-to-ship transfer. Shipments to Europe are primarily on smaller Suezmax and Aframax vessels. Overall, the increased marine activity is testing the limits of existing infrastructure. Today, we analyze the past 16 months of crude export vessel movements and their impacts on Gulf Coast ports. (We’ll also be discussing this and other critical trends related to U.S. export markets live and in person tomorrow at xPortcon in Houston.)
The AltaGas/Royal Vopak Ridley Island Propane Export Terminal in the Port of Prince Rupert, BC, is poised to receive and load its first Very Large Gas Carrier (VLGC) any day now, a milestone that will make it Western Canada’s first LPG export facility and only the second such terminal in the greater Pacific Northwest region. With a capacity of 40 Mb/d, the facility is likely to provide a healthy boost to Western Canadian propane exports in 2019, easing oversupply conditions in the region while also providing producers with enhanced access to overseas markets, particularly in Asia. Today, we take a closer look at the new Prince Rupert facility and what it means for the Western Canadian propane market.
Crude oil gathering systems do just that — they gather crude from multiple well sites — but the drivers behind their initial development can vary widely. Some gathering systems are developed by oil producers to reduce their use of trucks and more efficiently transport increasing volumes of crude from the lease to takeaway pipelines. Others are the brainchildren of savvy midstream companies that see an opportunity to serve multiple producers in a fast-growing production area. And then there are systems like the one refiner Delek US is now expanding in the Permian’s Midland Basin near the company’s Big Spring, TX, refinery. It’s designed to feed locally produced crude directly to that refinery — and possibly other Delek refineries too — and may potentially be used to help fill a long-haul takeaway pipeline that Delek still hopes to co-develop with partners. Today, we continue our series on Permian gathering systems with a look at Delek’s 200-mile Big Spring project, part of which is already up and running.
While it’s widely known that Canada’s natural gas prices and exports have been under increasing pressure from rising gas supplies in the U.S., forcing an ever-deeper discount for AECO — Canada’s primary gas price benchmark — versus U.S. benchmark gas prices, a homegrown development is making the situation worse. Growing unconventional gas supplies from the Montney and related plays in Western Canada are bumping up against insufficient pipeline takeaway capacity from this producing region. Will Canadian gas markets be able to adapt to all of these growing supplies on both sides of the border or simply wither away as U.S. supplies take more and more market share? Today, we kick off a multi-part series examining the highly complex problems facing Western Canadian gas producers.