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.
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Daily energy Posts
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.
The cascade of LNG export project news continues. In the past week, yet another “second-wave” U.S. LNG export project — NextDecade’s Rio Grande LNG — cleared FERC’s environmental review process. That follows news of three other projects that received their environmental approvals this month; plus two other projects — Tellurian’s Driftwood LNG and Sempra’s Port Arthur LNG — got final FERC authorization to construct their facilities, should they make the financial commitment to proceed; and, finally, plans for a brand new export terminal, Venture Global’s Delta LNG, were unveiled. All in all, there are more than 20 announced projects totaling 235 MMtpa (~35 Bcf/d) that are looking to catch the second wave of U.S. LNG exports in the next decade. The timing of their regulatory approvals and final investment decisions will determine, in part, when this next wave — or shall we say tsunami — of export demand will materialize. Today, we wrap up our second-wave LNG project update series with a look at the progress made by some of the remaining projects that we’re tracking.
The run-up in Permian crude oil production over the past few years — and the expectation of continued gains — has been spurring the development of a number of crude gathering systems in the play’s Midland and Delaware basins. These small-diameter pipeline networks are critically important to producers and shippers in that they enable them to transport crude more quickly and cost-effectively than by truck, and (ideally) they connect to takeaway pipelines that flow to multiple destinations. But there is more than one approach to developing a gathering system. For example, a midstream company could plan a system that appeals to several producers in an area and then try to sign them up. Or, it might work closely with a single producer — sometimes an affiliated company — and design a gathering system to meet its specific needs, then work to add other producers and shippers later. Today, we look at the West Texas and southeastern New Mexico systems developed by a joint-venture company of Matador Resources and Five Point Energy to serve Matador and others.
The biggest driver of generally rising LPG exports is the widening gap between how much LPG the U.S. consumes and how much it produces — there’s simply too much of the stuff, and LPG-hungry European and Asian markets beckon. But month-to-month export volumes are often erratic, affected by a wide range of variables. Winter weather in Wisconsin. Steam cracker economics in Germany. Propane dehydrogenation (PDH) plant outages in China. Not to mention lingering fog or a tank-farm fire along the Houston Ship Channel, or the startup of a new NGL pipeline to the Marcus Hook terminal near Philly. Add to all this the export-volume spikes that may come later this year and in 2020 when new dock capacity comes online along the Gulf Coast. Today, we take a look at what drives the monthly ups and downs in exports.
Wednesday’s blockbuster announcement that Occidental Petroleum is challenging Chevron’s definitive agreement to acquire Anadarko Petroleum with a considerably higher offer sent another shock wave across what had been mostly somnolent energy M&A and equity markets. Oxy’s $76/share bid — $11/share more than Chevron’s — valued Anadarko at a whopping 65% premium to its closing price the day before Chevron’s deal to acquire the company was unveiled on April 12. The prospective Oxy/Chevron bidding war provided some of the strongest evidence yet that investors overreacted to the fourth-quarter decline in oil prices when they drove down E&P stock prices by some 40%, as measured by the S&P’s E&P Stock Index. Why the lack of market love? Many U.S. E&Ps are doing very well, actually. In today’s blog, Nick Cacchione identifies and discusses the outstanding performers among the 44 U.S. E&Ps we track, and considers the factors that could drive profit improvement in 2019.