Energy Transfer’s Mariner East pipeline system was supposed to help resolve a growing problem for producers in the “wet” Marcellus and Utica plays — namely, the need to transport increasing volumes of LPG out of the Northeast, especially during the warmer months, when in-region demand for LPG is low. The pipeline system also was meant to spur LPG and ethane exports out of Energy Transfer’s Marcus Hook marine terminal near Philadelphia. So how are things going? Well, the now five-year-old, 70-Mb/d Mariner East 1 pipeline, designed to transport ethane and propane, has been offline ever since a sinkhole exposed a part of the pipe late last month. The 275-Mb/d Mariner East 2 pipe is finally in operation and enabling a lot more LPG to move to Marcus Hook, but for now it can only run at about 60% of its capacity. And last Friday, a key Pennsylvania regulator suspended its review of outstanding water permit applications for the remaining piece of ME-2 and the parallel 250-Mb/d ME-2 Expansion project, and threw into doubt how long it might take to finish the Mariner East system and ramp it up to full capacity. Today, we begin a series on recent Mariner East developments and explain how, despite the mixed bag of Mariner East news in recent weeks, the situation is not as bad as it may seem.
Daily energy Posts
Mexico’s energy sector has been dealing with a fair amount of uncertainty of late. Newly installed Mexican President Andrés Manuel López Obrador has promised to undo elements of the country’s historic energy reform program, limit imports of hydrocarbons, and focus on domestic production and refining. How much will all this affect the export of natural gas from the U.S. to Mexico? It’s too soon to know what the long-term impact might be, but for now, gas exports remain near record highs and the pipeline buildout within Mexico is proceeding. That’s not to say, however, that the infrastructure work has gone without its own set of challenges — many of those were apparent well before the recent political changes. Today, we begin a series examining the opportunities and potential pitfalls ahead this year for Mexico’s natural gas pipeline infrastructure additions.
When crude oil prices crashed in the second half of 2014 and 2015, producers survived by becoming leaner and more efficient. That transition included drastic reductions in the rates paid to services companies while wringing ever more oil and gas out of each well and, in the process, permanently altering the economics of drilling and completion. This year, producers are again facing a lower-price environment; since early October (2018), crude prices have dropped more than 30%. In the current, more conservative investment environment, can producers do it again? Can additional value be squeezed out with bigger well pads and longer laterals? Today, we continue a series exploring the benefits and risks of these highly concentrated and highly complicated operations.
Earlier this decade, East Coast refineries found it cost-effective to ramp down their crude imports and turn to the price-advantaged U.S. shale oil they could rail in from the pipeline-constrained Bakken or send up by tanker from the crude-saturated Gulf Coast. Things changed, though. New southbound crude pipelines out of the Bakken came online, the ban on most crude exports was lifted — providing a new outlet for Texas crude production — and the economic rationale for railing or shipping in domestic crude to PADD 1 refineries withered. Now, things have changed again. Most important perhaps, is that the price spread between WTI and Brent has widened, and once more it can make financial sense for these refineries to revert to crude-by-rail out of the Bakken and to shipping in crude on Jones Act tankers from Corpus Christi and other Gulf Coast ports. Today, we discuss these recent trends, what’s driving them, and how long they might last.
One of the biggest factors affecting the U.S. natural gas market in 2019 will undoubtedly be the dramatic rise in LNG export demand. The slate of liquefaction and LNG export capacity additions this year will boost U.S. demand for feedgas supply to nearly 9 Bcf/d by the end of the year, almost tripling the 2018 full-year average of 3.1 Bcf/d and close to doubling the December 2018 average of 4.6 Bcf/d, with the lion’s share of that growth happening along the Texas and Louisiana Gulf Coast. Three liquefaction trains — one each at Cheniere Energy’s Sabine Pass and Corpus Christi terminals, as well as one at Cameron LNG — are likely to be fully operational in the first quarter, with five additional trains due in rapid progression later in 2019. That much new gas demand concentrated in one region is bound to disrupt physical flows and pricing dynamics. Today, we wrap up the series with a look at the timing and feedgas routes for the final two facilities: Freeport LNG in Texas and Kinder Morgan’s Elba Island project in Georgia.
Record runs allowed U.S. refiners to continue a multiyear streak of strong margins in 2018 despite higher crude prices during the first three quarters and a weaker fourth quarter after product prices tanked along with crude in October. While rising crude prices threatened refinery margins, a high Brent premium over domestic benchmark West Texas Intermediate (WTI) kept feedstock prices for U.S. refiners lower than their international rivals. The availability of discounted Canadian crude also helped produce stellar returns for Midwest, Rockies and Gulf Coast refiners that are configured to process heavy crude. Product prices only weakened in the fourth quarter when gasoline inventories began to rise. Today, we highlight major trends in the U.S. refining sector during 2018 and look forward to 2019.
Throughout the middle and latter parts of the 2010s, crude oil production growth in major U.S. basins and in Western Canada — not to mention the end to the ban on most U.S. crude exports in December 2015 — has caused noteworthy shifts in crude flow patterns, stressed existing pipeline infrastructure, and highlighted the importance of crude storage and distribution hubs. A common theme through all this has been that more and more crude needs to find its way to the Gulf Coast, with its bounty of refineries and export docks. To that end, lately, there’s been a slew of new pipeline and export-terminal projects announced that are tied to the St. James crude trading hub, which is located in Louisiana, about 60 miles up the Mississippi River from New Orleans. Today, we begin a series on St. James and why it’s becoming an even bigger player in crude markets.
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.
With Petróleos Mexicanos’ (Pemex) refineries struggling to operate at more than 30% of total capacity, gasoline pumps across Mexico are more likely to be filling up tanks with fuel imported from the U.S. than with domestic supply. This arrangement works well for U.S. refiners, who are running close to flat-out and depending on export volumes to clear the market. But now, the Mexican government has shut a number of refined products pipelines to prevent illegal tapping, and that’s had two consequences: widespread fuel shortages among Mexican consumers and a logjam of American supplies waiting to come into Mexico’s ports. Today, we explain the opportunities and risks posed to U.S. refiners that have ramped up their involvement with — and dependence on — the Mexican market.
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.
Liquefaction capacity additions will add about 5 Bcf/d of natural gas demand in 2019, with almost all of that happening along the Texas and Louisiana Gulf Coast. The planned start-up of new liquefaction trains at the Sabine Pass, Corpus Christi, Cameron, Freeport and Elba Island projects means we can expect U.S. LNG export demand to double to nearly 9 Bcf/d by the end of the year. How fast will that new capacity and gas demand come on and how will the gas get to where it needs to be? Today, we take a closer look at the timing of the liquefaction capacity build-out and the related feedgas routes.
The possibility of reversing the flow on Capline — the U.S.’s largest northbound crude oil pipeline — has been discussed for a number of years now. Finally, it may be on the horizon. The three owners of Louisiana-to-Illinois pipeline announced last week that this month they plan to initiate a binding open season for a reversed Capline system that would enable southbound flows starting in the third quarter of 2020 — only a year and a half from now. And, as we discuss in today’s blog, reversing Capline’s direction could open up new crude-slate possibilities for Louisiana refineries and boost crude exports out of the Bayou State.
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.
In 2018, a handful of midstream companies started racing to develop deepwater export terminals along the Gulf Coast that can fully load Very Large Crude Carriers (VLCCs) with 2 MMbbl of crude oil from the Permian and other plays. While some of those companies are moving toward final investment decisions (FIDs) that would bring their plans to fruition in the early 2020s, terminal operators with existing VLCC-capable assets — both onshore and offshore — turned up the volume in a major way in December. Today, we outline the strides made in recent days by the export programs of the Louisiana Offshore Oil Port (LOOP), Seaway Texas City and Moda Midstream.
It’s so ironic. New England is only a stone’s throw from the burgeoning Marcellus natural gas production area, but pipeline constraints during high-demand periods in the wintertime leave power generators in the six-state region gasping for more gas. Now, with only minimal expansions to New England’s gas pipeline network on the horizon, the region is doubling down on a long-term plan to rely on a combination of gas liquefaction, LNG storage, LNG imports and gas-to-oil fuel switching at dual-fuel power plants to help keep the heat and lights on through those inevitable cold snaps. Today, we discuss recent developments on the gas-supply front in “Patriots Nation.”
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.