Everywhere you look these days, someone is talking about hydrogen and, if you’re not well-versed in emerging technologies aimed at reducing carbon, you may not know what any of it means. A quick internet search isn’t much help either, as you will likely get lost quickly in discussions of fuel cell efficiency and electrolysis technology developments, not to mention the various “colors” of hydrogen and the myriad of ways it can be stored and transported. Don’t bother turning to your traditional green energy gurus either, as hydrogen is just one of many competing approaches to reducing the world’s carbon footprint, and electric vehicle folks like Elon Musk aren’t big fans. All the same, hydrogen news and investment plans seem to proliferate daily, and understanding this fuel — which, by the way, is not new to the energy space — seems prudent. At least that’s our view, which is why we today start a series to help us hydrocarbon experts unravel the mysteries behind the recent hydrogen ruckus.
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.
On October 25, a major consolidation of two Canadian oil and gas companies was announced with the planned merger of Cenovus Energy and Husky Energy. The prospective consolidation will offer the opportunity for corporate-level synergies and, over the longer term, for the physical integration of some of the companies’ operations, especially in Alberta’s oil sands. In today’s blog, we discuss some of the more nuanced elements of the consolidation, including potential improvement in crude oil market access and the larger presence of the combined company in PADD 2 refining, a sector that has taken a major hit during the pandemic. This blog also introduces a new weekly report from RBN and Baker & O’Brien: U.S. Refinery Billboard.
Within the next year, the Permian Highway and Whistler natural gas pipelines will add 4.0 Bcf/d of incremental capacity from the Permian Basin to the Gulf Coast, with gas supplies on those pipes primarily targeting LNG exports. But in the years since these pipeline projects were initially envisioned, market conditions have been radically transformed by consequences of the COVID era, on both the supply and demand sides of the equation. The outlook for supply growth is lower, while the dependability of LNG exports has been thrown into question following massive cargo cancellations this summer. In RBN’s special-edition multi-client market study, titled Some Beach, we break down the consequences of these developments into eight distinct steps that demonstrate how Texas gas markets are likely to evolve as flows and basis respond. Today’s blog summarizes those conclusions.
Since August, physical natural gas flows at Henry Hub have been at all-time highs for each respective month, and, in early October, they recorded the highest single-day flows that we’ve seen since December 2009. For decades, liquidity at the U.S. natural gas benchmark pricing location in southeastern Louisiana has been dominated by financial trades, with minimal physical exchange of gas, despite the hub boasting robust physical infrastructure and ample pipeline connectivity. That’s still the case, but physical movements of gas in the area have been on the rise due to LNG exports ramping up from the Sabine Pass and Cameron LNG facilities in southwestern Louisiana and a slew of Appalachia gas supply pipelines targeting that export demand. As more physical gas is moving through the hub, operational constraints are developing at key interconnects there. That, along with the ups and downs of LNG feedgas demand, is contributing to spot price volatility at the hub and, at times, a deeper divergence between Henry spot and futures prices. Today, we begin a short blog series on the changing gas flow dynamics in and around Henry.
On December 1, the government of Alberta will officially end its nearly two-year-old policy of curtailing crude oil production to help shrink the massive price discounts that producers had been enduring. It would hardly be an overstatement to say that North American oil markets have changed dramatically since the production cap was implemented by Canada’s largest oil-producing province in January 2019. A short-but-bruising oil price war and a pandemic that slashed demand for crude resulted in Alberta producers making supply cuts even bigger than their government had mandated. Today, we look back at the provincial government’s policy and what has changed to motivate its suspension.
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.
2020 has been as anomalous as it can get for energy markets, but that’s especially the case for the LNG sector, which was battered by COVID-related demand destruction. U.S. export volumes, in particular, experienced wild swings this year, going from steady increases and close to 100% utilization over the past few years as new export capacity was added, to operating at barely 30% of capacity this past summer as national lockdowns decimated demand and led to historically low gas prices abroad. Contracted cargoes were canceled en masse for the first time since the U.S. began exporting in 2016, amounting to over 500 Bcf between June and September that was pushed back into the U.S. natural gas market and into storage. But these events only exaggerated what was already a growing risk; with each new train being commercialized, domestic markets are increasingly exposed to the demand swings and other fundamentals in the export markets it serves. Today, we look at how seasonal demand patterns in the U.S.’s primary destination markets could translate to increased volatility at home.
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.
The natural-gas market disruptions hitting the Texas-Louisiana coast so far in 2020 — a pandemic, the collapse of the LNG export market, a rare hiccup in Permian gas production, and multiple hurricanes —threw a big wrench into market expectations. Everything had been moving along pretty smoothly since mid-2016, when the first of a series of new liquefaction trains came online at Sabine Pass LNG. As new LNG export capacity started up at Sabine Pass, Corpus Christi, Cameron, and Freeport, so did relatively steady, predictable growth in feedgas demand. Then came this crazy, unforgettable year. Still more liquefaction capacity started up, but LNG export volumes plummeted, mostly due to very weak export economics. Recently, LNG exports have been picking up and, whenever hurricanes stop pounding the Gulf Coast, the U.S. will likely finally experience the full impact of all 9.15 Bcf/d of export capacity operating at full strength, requiring nearly 10 Bcf/d of feedgas across the U.S, almost 9 Bcf/d of which is located in Texas and Louisiana. Gas flow patterns across Louisiana’s dense network of pipelines already are shifting in response to the incremental demand and are signaling increased supply competition along the Gulf Coast this winter. Today, we continue our series discussing the changing flow patterns along the U.S. Gulf Coast, this time providing an overview of the main drivers of those shifts to date, including LNG feedgas demand and Northeast inflows.
Natural gas production has been growing in Western Canada in recent years with an increasing share of that supply coming from core areas of activity within the Montney and Duvernay plays. This tighter focus has forced TC Energy to rework and expand its giant Nova Gas Transmission Limited pipeline system, a network that originally gathered gas supplies across a much larger geographic footprint. The problem is, it took far longer than expected for the latest round of NGTL expansions to win final approval from Canadian regulators. Today, we review the next phase of the pipeline’s system development, and what the regulatory delay might mean for Western Canada’s gas market.
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 several months, U.S. refineries have been producing more distillate than demand warrants, resulting in a glut of distillate fuels, especially ultra-low-sulfur diesel and jet fuel. The disconnect between supply and demand has been particularly stark in the Gulf Coast region, where just a couple of weeks ago distillate stocks sat 39% above their 10-year average after coming perilously close to tank tops in August. The culprit, of course, is COVID-19, or more specifically the effects of the pandemic on air travel and the broader economy. Demand for motor gasoline rebounded more quickly than demand for ULSD and jet fuel, and refineries churned out more gasoline to keep up, but that results in more distillate too. Now, finally, there are signs that distillate stocks may be easing back down. Today, we discuss the build-up in ULSD and jet fuel stockpiles, the ways they might revert to the norm, and the potential for storing distillate now and selling it at a higher price later.
Down to only two months left in 2020. Whew! We’ll all be relieved to see this one disappear in the rear-view mirror. It’s been an extreme roller coaster ride for oil and gas — from the onset of the COVID pandemic and the crude price collapse in the spring, to withering demand for transportation fuels, to one hurricane after another, to chaotic swings in natural gas prices. And being thrashed about by all this turmoil are the natural gas liquids, with each NGL product taking its own wild ride through erratic market conditions. It’s been a challenge just keeping up with what is going on. At RBN, we’ve been working on a new app to address this challenge, and today we are rolling it out to you, as a reader of our daily blog. We are talking about access to everything from spot and futures prices, to market statistics, to reports on intra-day pricing, and to market alerts as they happen. Sound interesting? If so, hang on to your hat and read on in this RBN product advertorial.