U.S. oil, natural gas and NGL markets are more interconnected than ever — with each other and with global dynamics. The deep connections we see today have evolved in the 15 years since the start of the Shale Revolution, and in recognizing how the various segments have impacted one another, we can better explain how they are driving today’s markets. That was the focus of our Fall 2023 School of Energy and it’s the subject of today’s RBN blog, which (warning) is a blatant advertorial for School of Energy Encore, a newly available online version of our recent conference.
Enterprise Products Partners doesn’t just extract mixed NGLs from associated gas at processing plants, transport that Y-grade to the NGL hub at Mont Belvieu, and fractionate NGLs into “purity products” like ethane, propane and butanes. The midstream giant also distributes purity products to Gulf Coast steam crackers and refineries, converts propane to propylene at its two propane dehydrogenation (PDH) plants, distributes ethylene and propylene, transports propane and butane to wholesale markets across much of the eastern half of the U.S., and exports a wide range of products — ethane, LPG, ethylene and propylene among them — from two Enterprise marine terminals on the Houston Ship Channel. (Another export terminal in Beaumont, TX, is in the works.) Talk about a value chain! In today’s RBN blog, we continue our series on NGL networks with a look at Enterprise’s NGL and petrochemical production, distribution and export assets.
The energy industry’s upstream products — crude oil, natural gas and NGLs — are commodities, so the lowest-cost producers generally do best, especially if they are well-connected to downstream markets. Due in large part to the intensity of competition, finite drilling locations, the constant need for capital investment and the chilling effect of political headwinds, the industry is in the middle of a consolidation cycle that has enabled a select group of top-tier E&Ps to build scale — and longer-lasting inventories — in the most productive parts of the most lucrative shale plays. That scale, in turn, helps these Shale Era winners reduce their costs, gain market share and — important in 2023 and beyond — return a big slice of their free cash flow to investors as dividends and stock buybacks. In today’s RBN blog, we discuss what’s driving that “urge to merge” and what it means for industry players large and small.
Whether it’s crude oil, natural gas or some other buried treasure, there’s one piece of advice from Indiana Jones that still rings true — finding it is never as easy as “X marks the spot.” Well-site preparations and drilling can take long enough on their own, but that doesn’t account for the time it takes to ensure — or at least raise the odds — that those all-important hydrocarbons will actually be found. In today’s RBN blog, we look at how seismic surveys are conducted and the key steps in permitting and well-site preparation.
Back in late March and early April, U.S. refineries responded to the sudden falloff in demand for jet fuel and motor gasoline by quickly ramping down their operations. Similarly, E&Ps in recent weeks have reacted to sharply lower demand for crude oil by slowing — or even suspending — their drilling activity and shutting in wells. Midstream companies’ actions have generally been more muted, though. While many midstreamers have ratcheted back their planned 2020 capital spending plans, the bulk of their major crude oil, natural gas and NGL projects already under construction are staying on-plan. Most of the rest are only being delayed by a few months, and a handful are either being reworked or deferred indefinitely. Today, we consider the midstream sector’s seemingly modest response to the crashes in crude oil prices and demand.
Crude oil production in the Permian grew steadily through the 2010s and now tops 4.5 MMb/d — five times what it was at the start of the decade. Production in the Bakken and the Denver-Julesburg (D-J) Basin sagged when crude prices plummeted in 2014-15, but both regions chugged their way back, with output setting new records every month or two in 2018-19. SCOOP and STACK are another story. Only a year or two ago, many producers and others were talking up the neighboring crude-focused plays in central Oklahoma as the next big thing, maybe even a Sooner State Permian. But while SCOOP/STACK production increased through 2018, it’s been flat or falling ever since, and most producers there have been slashing their drilling activity. Today, we look at recent developments in the once-hot region.
Offer any energy commodity at a low-enough price and buyers will surface, as long as there’s a way to get that liquid or gas from where it’s being sold to where it’s being used or put on a boat for export. That’s been the recent experience of the butane market in Western Canada, where a perfect storm of events last fall caused butane prices in Edmonton, AB, to freefall to near zero. But things have turned around, at least for now. Today, we take a look at the dramatic recovery of the Edmonton butane market and what might lie ahead.
Keyera Corp. and SemCAMS Midstream, two major midstream players in Western Canada, in mid-May announced they are proceeding with the construction of their joint-venture project — a new NGL and condensate pipeline system out of the liquids-rich Montney and Duvernay plays of Alberta. The planned Key Access Pipeline System would provide the first direct competition for the transportation of NGLs and condensate out of these producing regions, currently dominated by Pembina Pipeline Co. Any and all transportation options for the movement of condensate and other NGLs out of the Montney and surrounding plays will likely be welcomed by Western Canadian natural gas producers, who are looking to capitalize on oil-sands producers’ growing demand for homegrown sources of condensate for use as diluent in bitumen transportation. Today, we provide key details about the project and how it fits into the region’s existing condensate/NGLs market.
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.
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.
What a deal! Take as much butane as you want — all for the low, low price of less than 10 cents/gallon (c/gal). That was the situation in Edmonton, AB, last November and the price stayed dirt cheap until a few days ago. Given a decline in demand for butane in crude blending, along with growing NGL production, the NGL processing and storage hub in Western Canada was awash in butane as winter approached. It remains flush with product today — and the price for Alberta butane is still low. How did this happen, and how will it play out over the next few months? Today, we examine the factors that led the Edmonton NGL market to see a price fall to near zero c/gal for the second time this decade.
LPG export terminals along the Gulf Coast account for more than nine of every 10 barrels of propane and normal butane that are shipped from the U.S. to foreign buyers. That makes perfect sense, given the terminals’ proximity to major NGL production areas like the Permian, the Eagle Ford and SCOOP/STACK, and to the world-class fractionation hub in Mont Belvieu, TX. But, increasingly, LPG terminals on the East and West coasts, are growing in significance. On the Atlantic side, Marcus Hook, near Philadelphia, is enabling more and more volumes of Marcellus/Utica-sourced propane and butane to reach overseas markets. And, as we discuss in today’s blog, West Coast exports are on the rise as well, with Petrogas’s Ferndale terminal in Washington state providing a straight shot across the Pacific to Asia for propane and butane fractionated in Western Canada, plus a good bit more LPG export capacity under development in British Columbia.
U.S. production of natural gas liquids is projected to increase by 17% this year, and by another 10% in 2020, according to RBN’s forecast. These gains will result in similar increases in the output of propane and normal butane — two NGL purity products generally referred to as LPG — and, with U.S. demand for LPG expected to stay relatively flat, most of the incremental volumes will be sent to export terminals for shipment to foreign buyers. The question is, will the nine U.S. marine terminals that are equipped to send out LPG have enough capacity to handle the much-higher flows? Today, we continue our series with a review of four smaller export terminals along the Gulf and East coasts.
LPG exports out of Gulf Coast marine terminals averaged 1 MMb/d in 2018, a gain of 12% from 2017 and 35% from 2016. And, with U.S. NGL production rising steadily, 2019 is looking to be another banner year for LPG shipments to overseas buyers. The increasing volume of propane and normal butane — the NGL purity products generally referenced as LPG — is filling up the existing export capacity of the Gulf Coast’s six LPG terminals and spurring the development of a number of expansion projects. Today, we continue our blog series on propane and butane export facilities along the Gulf, West and East coasts, and what’s driving the build-out of these assets.
Way back in 2012, the U.S. flipped from being a net LPG importer to a net exporter. Since then, exports by ship have skyrocketed, up from 0.3 MMb/d in 2013 to more than 1.1 MMb/d at year-end 2018, an astronomical compound annual growth rate (CAGR) of 30%. The vast majority of waterborne exports was out of a handful of LPG terminals along the Gulf Coast. These facilities — plus Ferndale in the Pacific Northwest and Marcus Hook near Philadelphia — so far have managed to handle the increasing flow of LPG, but with U.S. NGL production still rising, it looks like new export capacity is needed — and is on the way. All the while, imports of LPG, almost all from Canada, have remained relatively flat, averaging only 130 Mb/d in the 2013-18 period. Today, we begin a series on existing and planned LPG export capacity along the Gulf, West and East coasts — and what’s driving the build-out of these assets.