Natural gas pipeline takeaway capacity additions out of the Northeast over the past year or two, along with suppressed gas production growth in recent months, have relieved years-long and severe constraints for moving Marcellus/Utica gas out of the region and even left some takeaway pipelines less than full. That, in turn, has supported Appalachian supply prices. Basis at the Dominion South hub in the first five months of 2019 averaged just $0.26/MMBtu below Henry Hub, compared with $0.46 below in the same period last year and nearly $1.00 below back in 2015, when constraints were the norm. Today, we continue our series providing an update on pipeline utilization out of the region, and how much spare capacity is left before constraints reemerge.
Daily energy Posts
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.
Permian natural gas prices have been on a wild ride lately, trading more than $5/MMBtu below zero in early April before recovering to just above zero over the last few weeks. It’s hardly a secret that the Permian’s gas market woes have been the direct result of production exceeding pipeline capacity. That situation is set to change in a few months, when Kinder Morgan starts up its 1.98-Bcf/d Gulf Coast Express Pipeline, providing much needed new takeaway capacity. And that’s not all GCX will do. Its start-up will shift huge volumes of gas toward the Texas Gulf Coast that currently flow out of the Permian to other markets, likely causing a ripple effect across more than just the West Texas gas market. Today, we look at how Kinder Morgan’s new gas pipeline will redirect significant volumes of Permian gas currently flowing north to the Midcontinent.
The Houston Ship Channel (HSC) is one of the busiest shipping lanes in the U.S. Each year, thousands of vessels utilize the waterway, importing and exporting goods ranging from pharmaceutical products to what the Census Bureau classifies as “Leather Art; Saddlery Etc.; Handbags Etc.; Gut Art”. More to the point of today’s blog: over 10 million tons of energy products move through the channel each month. But as ships grow ever larger, the ports and canals that service them must also adapt to be able to handle their increased dimensions. The Houston Ship Channel now finds itself in a situation where it must adapt to meet increasing market demands. Today, we continue our series on the issues facing some Texas ports and the measures being taken to help alleviate them.
U.S. exploration and production companies (E&Ps) are tapping the brakes on their capital spending in 2019 after two years of strong investment growth and a return to profitability that in 2018 approached the level generated in the $100+/bbl crude oil price environment back in 2014. The pull-back in capex this year appears likely to slow the pace of production growth, and comes despite a 30% rebound in crude oil prices in the first quarter of 2019. What’s going on? Well, many investors remain skeptical about E&Ps, as evidenced by stock prices that remain in the doldrums, and to gain favor with investors, a number of E&Ps are returning cash to them in the form of share buybacks and higher dividends. Today, we consider the current state of investment in the E&P sector, how it’s affected by stock valuations and how it affects production growth.
Crude oil gathering systems are, by their very nature, growing and evolving things, especially in super-hot shale plays like the Permian. These systems typically sprout when economics and the expectation of growing production support the development of small-diameter pipeline networks to transport crude from the lease to takeaway pipes — reducing the need for truck deliveries in the process. They then are organically extended as drilling-and-completion activity expands into nearby areas. Over time, some crude gathering systems grow so large — and are so well interconnected with takeaway pipelines — that they become intra-basin header systems that allow shippers to move crude to many interconnection points, thereby providing the highest level of destination optionality. Today, we look at one such highly evolved gathering system — Medallion Midstream’s gathering/header network in the Midland Basin — and at other Medallion pipes that gather Delaware Basin crude oil.
It may be easy to forget in these days of Permian this and Permian that, but crude oil production in the offshore Gulf of Mexico (GOM) set a number of new, all-time records in the past couple of years. Better yet, with a handful of key producers in the Gulf planning low-cost, subsea tiebacks to existing platforms — and still discovering more oil — it’s a good bet that offshore production will continue its upward trajectory into the early 2020s. And, unlike U.S. shale wells, whose production peaks early then trails off, wells in the GOM typically maintain high levels of production for years and years. Where do offshore production and drilling activity stand in the Shale Era, and where are they headed? Today, we review recent production gains in the Gulf and examine why the GOM remains the oil sector’s Energizer Bunny.
With U.S. natural gas production levels near all-time highs and storage injections running strong, LNG exports will be a critical balancing item for the domestic gas market this year. Yet feedgas demand in recent months has been anything but stable; rather, it’s proving to be susceptible to volatility, driven by a combination of offshore weather conditions, maintenance events, start-up activity and global market conditions, among other factors. At the same time, timelines for the remaining 20 MMtpa (2.6 Bcf/d) of new liquefaction capacity still due online this year are moving targets as coastal weather, construction-related delays and other variables affect target completion dates. Today, we discuss highlights from our new Drill Down Report on the impacts of recent and upcoming LNG export capacity additions.
Old age and treachery will always beat youth and exuberance. So the saying goes, and it often holds true for midstream projects as well as people. Many times we’ve written that existing pipe in the ground beats new pipeline projects; it’s frequently easier and faster to expand the capacity of an older pipe than it is to build an entirely new pipeline. But eventually, contracts on these old pipelines expire, and as they do, shippers may have new, more attractive options — maybe proposed new pipes offer better connections to gathering systems, the ability to segregate batches of crude oil, and/or access to more desirable markets. Most importantly, they probably are willing to charge a lower tariff. In the Permian, we’ve seen a slew of new pipelines advance to construction by promising lower and lower shipping costs to move crude from West Texas to the Gulf Coast. Today, we look at how older pipelines’ re-contracting efforts will be affected by their competitors’ lower tariffs and operational advantages.
In terms of raw tonnage, the Port of Houston is by far the busiest in the United States. The 52-mile-long Houston Ship Channel (HSC) — running from just outside downtown Houston out to an area between Galveston Island and Bolivar Peninsula — is the artery that enables the heavy ship traffic, much of it tied to crude oil, LPG, petroleum products and other hydrocarbons. But in the same way that Houston’s Interstate 45 traffic backs up during the morning commute, the ship channel traffic, which normally runs at about 60% of peak levels, can be (and has been) subject to delays when there’s an accident, visibility problems, or a slow-moving double-wide taking up two lanes. With energy-related export activity on the rise, efforts are underway to address those issues. Today, we begin a series on the issues facing some Texas ports and the measures being taken to help alleviate them.
The Texas natural gas market is rapidly evolving, in large part due to burgeoning Permian production but also due to gas production gains in East Texas driven by strong returns on new wells in the Haynesville and Cotton Valley plays. Most of this supply growth is looking to make its way to the Gulf Coast, where close to 5 Bcf/d of LNG export capacity is operational and plenty more is under construction. The combination of fast-rising supply and demand is straining the existing gas pipeline infrastructure across Texas, creating the need for more capacity. The Permian has been grabbing the headlines for its extreme takeaway constraints and depressed, even negative supply-area prices, and all eyes are trained on the announced pipeline projects that will eventually provide relief to the region. But pipeline constraints also are developing between the Haynesville and the Texas coast. Today, we discuss the latest solution for the intensifying Haynesville-area supply congestion.