U.S. crude oil exports are off from the record highs they reached earlier this year, leaving the Gulf Coast even more flush with surplus export capacity than it had been going into 2020. And yet … Energy Transfer is developing an crude export terminal off the coast of Beaumont, TX, that would be capable of fully loading a 2-MMbbl VLCC every day or so. Is the company’s Blue Marlin project based simply on a hunch that U.S. oil production and exports will rebound over time and eventually leave PADD 3 short of dock and ship-loading capacity? Or is Energy Transfer’s proposed offshore terminal, with its extensive re-use of existing infrastructure, a cost-efficient way of giving oil-sands, Bakken and other producers more direct access to deep water and the supertankers that long-distance shippers prefer? Today, we discuss what may be behind the seemingly long-shot effort to develop new export capacity in a region that’s already got way too much.
Posts from Housley Carr
Back in 2005, marine terminals along the Gulf Coast were importing more than 6 MMb/d of crude oil, mostly to feed refineries within PADD 3 but also to pipe or barge north to PADD 2. By 2019, with U.S. shale production finishing up a decade-long rise, imports to the Gulf Coast had declined to less than 1.7 MMb/d. In COVID-impacted 2020, imports sagged, soared, then sagged again, recently settling in at about 1.2 MMb/d, their lowest level in — wait for it — 35 years! The 80% decline in Gulf Coast oil imports since the mid-2000s was made possible in part by big changes in the crude slates at refineries in Texas, Louisiana, and other PADD 3 states, mostly involving the swapping out of light sweet crude from overseas with favorably priced light sweet crude from the Permian and other U.S. shale plays. Today, we look at imports into PADD 3, the home of more than half of the U.S.’s total refining capacity.
There’s no question, the pressures on many U.S. midstream companies have been steadily increasing for some time now, and the past few months have really tested them. Like exploration and production companies, refiners, and others in the energy space, midstreamers have seen their well-considered plans for 2020 upended by demand destruction, commodity-price gyrations, and cutbacks in capex, drilling, and production. While it may be tempting to simply wait out the last few weeks of this crazy, unforgettable year and hope that 2021 will be better, there’s actually at least some good news out there for the midstream sector, and good reason to believe that midstreamers have been positioning themselves to financially weather whatever next year may have in store. Today, we discuss highlights from East Daley Capital’s newly issued 2021 Midstream Guidance Outlook, which focuses on key trends affecting midstream asset owners.
Fifteen years ago, just before the dawn of the Shale Era, more than 1.8 MMb/d of Gulf Coast and imported crude oil was being piped and barged north from PADD 3 to refineries in the Midwest. By 2019, those northbound flows had fallen by half, to less than 930 Mb/d, and in the first nine months of this year they averaged only 550 Mb/d. Refineries in PADD 2, many now equipped with cokers and other hardware that enables them to break down heavy, sour crude into valuable refined products, have replaced those barrels — and more — with piped- and railed-in imports of favorably priced crude from Western Canada, including a lot of dilbit and railbit from Alberta’s oil sands. Today, we discuss the evolution of feedstock supply to the Midwest refinery sector.
For a few years now, refineries in the eastern part of PADD 2 — feedstock-advantaged and capable of producing far more refined products than their regional market can consume — have been eyeing the wholesale and retail markets to their east in PADD 1. Their thinking has been, if they could just pipe more of their gasoline and diesel into Pennsylvania, upstate New York, and adjoining areas, they could sell the transportation fuels at a premium and take market share. Well, things are looking up for PADD 2 refineries pursuing this strategy. Not only has new pipeline access to the east been opening up, but PADD 1’s refining capacity has been shrinking fast, leaving East Coast refineries less able than ever to meet in-region demand. Today, we discuss recent developments in the battle for refined-product market share in the Mid-Atlantic region.
Bombarded by COVID-related demand destruction and weak — sometimes dismal — crude oil pricing, producers have been pulling in their horns this year, and midstream companies have been doing the same. A number of major pipeline projects have been delayed, scrapped, or simply removed from midstreamers’ slide-deck presentations, having failed to garner the long-term shipper commitments they needed to remain viable in this era of retrenchment and fingers-crossed-we-survive. Even with the 2020 pullback in pipeline development, at least a couple of major production areas — the Permian and the Bakken — may well end up with considerably more takeaway capacity than they will need for the foreseeable future. Today, we discuss the oil pipeline projects that have stalled or died this year, and the ones that have managed to move forward despite it all.
The leaves have already fallen off New England’s trees, the first snow has come and gone, and the six-state region is preparing for another long, cold winter — this time with no Tom Brady and little hope that their beloved Patriots will make it to the playoffs. There is at least some good news, though: record volumes of propane have been railed or shipped into New England and put in storage, which should help to ensure that the many homes and businesses that depend on the fuel for space heating will stay warm. Today, we discuss propane supply and demand in the northeastern corner of the U.S., including a look at SEA-3 Newington — New England’s largest propane storage and distribution center, which rails in the fuel from the Marcellus/Utica and Canada and imports and exports propane by ship.
A few years ago, the most damning things skeptics could say about using LNG as a fuel for large ocean-going ships were that very few ships were fitted with LNG storage tanks and that there was little or no infrastructure in place at most ports to load the fuel. Well, they can’t say that anymore. About 170 large, LNG-powered vessels already are in operation around the world — including a French containership that just set a world record for carrying the most containers — and another 220 or so are on order. Just as important, the vast majority of key ports either have robust LNG bunkering operations in place or are in advanced stages of developing them. Today, we continue our series with a look at LNG’s growing acceptance and use as a ship fuel.
Ten years ago, East Coast refineries imported virtually all of the crude oil they needed — 60% from OPEC, 21% from Canada, and 19% from other non-OPEC countries. Only five years later, in 2015, the tables had turned. PADD 1 refinery demand for crude remained unchanged at 1.1 MMb/d, but only 14% of the oil refined there came from OPEC, 23% from Canada, and 21% from other non-OPEC countries — the other 42% was either railed in from the Bakken or shipped in from the Eagle Ford and Permian. But the changes didn’t end there. Imports rebounded sharply in 2016 and 2017, when new pipelines were built out of those basins that pulled barrels away from PADD 1 and into more competitive refining markets. In the fall of 2020, imports are falling back again but for a different reason — with COVID-19 demand destruction and other woes, East Coast refinery demand for oil is down by almost half, with more cuts on the way. Today, we continue a series on U.S. oil imports with a look at the East Coast.
Over the past 10 years, there’s been a 14-fold increase in U.S. LPG exports: from 132 Mb/d, on average, in 2010 to 1.85 MMb/d so far in 2020. That extraordinary growth in export volumes couldn’t have happened without the development of a lot of new, costly infrastructure — everything from gas processing plants, NGL pipelines, and fractionators to LPG storage capacity, marine terminals, and ocean-going gas carriers. And that build-out continues, not only along the Gulf Coast but on the shores of the Delaware River near Philadelphia. Energy Transfer has been working to expand the throughput of its Marcus Hook terminal on the Pennsylvania side of the river, and Delaware River Partners, an affiliate of Fortress Transportation & Infrastructure, will soon be transloading LPG from rail tank cars onto ships across the Delaware in New Jersey. Today, we discuss Delaware River Partners’ Gibbstown Logistics Center.
Condensates are quirky as heck — everyone’s got his or her own definition of what they are, for one thing — and their very quirkiness has sent condensates on a wild ride during the Shale Era. For example, the U.S. government for years categorized “conde” as a very light crude oil, and the long-standing ban on most crude exports meant you couldn’t export the stuff to anywhere but Canada. Unless, that is, you ran conde through a splitter to make NGLs, naphthas, and kerosene — those are petroleum products and they could (and still can) be exported, no questions asked. Then, as condensate production started soaring, especially in the Eagle Ford, the feds said that if you “processed” conde in special equipment to make it less volatile you could export it — no splitting required. That made the folks who invested in splitters shout in unison, “Huh?!” The roller-coaster for conde didn’t end there. The U.S. soon lifted the ban on all crude exports, and suddenly you didn’t need to process condensate at all to export it. More upheaval ensued. Today, we discuss this peculiar grouping of hydrocarbons.
Back in January, when the International Maritime Organization implemented more stringent limits on sulfur emissions for large, ocean-going vessels, the vast majority of shipowners and charterers complied with the new rule — commonly referred to as IMO 2020 — by switching to very low sulfur fuel oil or gasoil. A few others stuck with old, higher-sulfur bunker but installed scrubbers to remove sulfur from the engine exhaust. A third option — fueling ships with LNG — is now gaining traction, in part because it could help shipping companies deal with future IMO mandates on reducing greenhouse gas emissions. Orders for new-build LNG-powered vessels and LNG bunker ships are rolling in, and plans for port infrastructure to support LNG bunkering are being implemented. Today, we begin a series on the growing use of LNG in global shipping.
For the past few years, demand for U.S.-sourced ethane has been on the rise as petrochemical companies in the U.S. and abroad developed new, ethane-only steam crackers and retrofitted existing crackers to allow more ethane to be used as feedstock. U.S. NGL production was increasing too, of course, alongside growth in crude oil-focused plays like the Permian and “wet” gas plays like the Marcellus/Utica. But recently, drilling-and-completion activity has slowed to a crawl and NGL production has been leveling off, which means that less of the ethane that comes out of the ground with oil and gas will be “rejected” into natural gas and more will be separated out at fractionation plants. Today, we conclude a series on ethane exports with a look at U.S. NGL production, ethane supply and demand, ethane exports, and ethane prices.
Much has been written about the run-up in U.S. crude oil exports over the past five-plus years, and rightly so. Who would have guessed a dozen years ago that the U.S. would soon be producing as much as 13 MMb/d, and exporting one-quarter of it? Exports are only half of the story though. In fact, for every barrel of crude shipped or piped out of the U.S. today, two barrels of crude are shipped, piped, or railed in. Put simply, the U.S. refining sector still needs imported oil — or, more accurately, it can’t use all of the light, sweet crude that’s produced in the Permian and other shale/tight-oil plays in the Lower 48, and it still requires large volumes of the heavier crude that’s produced in Canada, Mexico, and overseas. Today, we begin a blog series on U.S. oil imports with a big-picture look at how crude sourcing for the refining sector has morphed in the Shale Era.
Last week, Hurricane Delta became the latest of a string of hurricanes and tropical storms that have assaulted the Gulf Coast this year and disrupted energy production in the Gulf of Mexico — and energy exports. A number of major storms made direct hits or glancing blows to crude export centers like Corpus Christi, Houston, Beaumont, and Louisiana, forcing marine terminals to either slow down their carrier-loading operations or shut down for a few days at a time. That led to a yo-yoing of weekly export volumes: way down one week, way up the next. Despite the short-term dislocations, however, total export volumes since the hurricane season started on June 1 are actually up slightly from the first five months of 2020, a testament to the resilience not only of the export market but to the marine terminals themselves. Today, we discuss how hurricanes and tropical storms have been affecting export-terminal activity.