Canadian gas storage levels concluded the most recent heating season at multi-year lows, especially in the western half of the nation, which hit a 16-year low at the end of March. Though storage sites have been refilling at a steady rate so far this summer, storage in the west, a region vitally important for balancing the North American gas market during high winter demand, remains unusually low for this time of year. In today’s RBN blog, we examine the latest developments in Canadian natural gas storage and explain why storage levels in Western Canada may start the next heating season at critically low levels.
Recently Published Reports
|NATGAS Billboard||NATGAS Billboard - June 30, 2022||2 hours 51 min ago|
|Chart Toppers||Chart Toppers - June 30, 2022||5 hours 9 min ago|
|NATGAS Appalachia||NATGAS Appalachia – June 29, 2022||16 hours 43 min ago|
|Crude Gusher||Crude Oil GUSHER - June 29, 2022||17 hours 32 min ago|
|U.S. Propane Billboard||U.S. Propane Billboard Weekly - June 29, 2022||18 hours 40 min ago|
Daily energy Posts
The oil and gas industry has historically been roiled by global economic and political crises, from the oil embargo in 1973 to the Great Recession of 2008 to the onset of the global pandemic in early 2020. However, amid the economic and political turmoil from the war in the Ukraine, rampant inflation and supply chain disruptions, E&P companies in recent weeks reported strong results for the first quarter of 2022, riding the wave of rising commodity prices as record volumes of cash flowed into corporate coffers. Producers successfully absorbed service cost increases and resisted calls to abandon their profits-focused fiscal discipline to generate Q1 2022 pre-tax operating earnings and cash flows that were up 25% and 12%, respectively, from the two-decade-high results recorded in the last quarter of 2021. In today’s RBN blog, we detail the industry’s outstanding results and preview its performance for the rest of the year.
Refinery closures. Shifting demand for gasoline, diesel and jet fuel. Yawning price differentials for refined products in neighboring regions. These and other factors have spurred an ongoing reworking of the extensive U.S. products pipeline network, which transports the fuels needed to power cars, SUVs, trucks, trains and airplanes — not to mention pumps in the oil patch, tractors and lawnmowers. New products pipelines are being built and existing pipelines are being repurposed, expanded or made bidirectional, typically to take advantage of opportunities that midstreamers, refiners and marketers see opening up. In today’s RBN blog, we begin a review of major pipelines that batch gasoline, diesel and jet fuel and look at the subtle and not-so-subtle changes being made to the U.S. refined products distribution network.
As the price of gasoline continues its seemingly never-ending upward path in the U.S. (not withstanding a bit of a pause in the past week), the cause (or blame, if you prefer) continues to shift. Of course, the Biden administration has heavily promoted the phrase “Putin’s price hike,” and the Russian president can certainly claim some of the blame. His invasion of Ukraine and the subsequent sanctions on the world’s second-largest exporter of refined products (after the U.S.) have led to the loss of several hundred thousand barrels per day of product supply. However, prices for refined products were already rising before his late February invasion due to a variety of other factors, both on the supply and demand sides of the equation. Perhaps the most important factor has been the loss of significant U.S. refining capacity over the last few years, which is limiting the ability of refiners to respond to the strong demand recovery and loss of supply. In its highly publicized June 15 letter to U.S. oil executives, the administration acknowledged this as it demanded refiners reactivate lost capacity and increase production. In today’s RBN blog, we summarize the shutdowns which have taken place in the U.S. and discuss the reasons behind those closures.
It’s well understood that methane is a significant greenhouse gas and that reducing methane emissions from oil and gas production is critical to hitting long-term emissions targets, but that’s about where most of the common ground ends. There are serious disagreements about the actual magnitude of methane emissions, the proper role of government regulation, and whether requirements to control those emissions would place an undue burden on the energy industry and lead to decreased supply. In today’s RBN blog, we look at how emissions estimates are made, why they can vary significantly, and how the disagreements about how to curb those emissions might be resolved.
In film and television, the “boxed crook” trope is where a condemned person is sought as a last-ditch effort to pull off some impossible mission or overcome a formidable opponent. In return, the convict is typically offered amnesty or other consideration by the operatives in charge. Millennials will probably think of the recent Suicide Squad movies. For Generation X, The Rock starring Sean Connery was a great example. And for the boomers, it was The Dirty Dozen. Our current situation in the U.S. energy sector may not be quite as thrilling as those movies but the same plot elements exist. In today’s RBN blog, we discuss the predicament faced by industry and political leaders and begin to sort out the various proposals to put a lid on prices and restore energy security.
One of the biggest, most important steps in the U.S.’s ongoing energy transition will be the selection and build-out of at least four new clean hydrogen hubs –– development supported to a significant degree by an $8 billion commitment in last year’s bipartisan infrastructure bill, which was signed into law by President Biden in November. Surely there will be a lot of angling among states and regions to land big chunks of that federal money, but it’s a safe bet that one of the new hydrogen hubs will be located along the Texas-Louisiana coast. After all, this stretch of low-lying land not only boasts the U.S.’s highest concentration of existing hydrogen production and consumption, it also offers an extensive network of hydrogen pipelines, easy access to vast amounts of natural gas and renewable power, scores of potential sites for underground hydrogen storage and carbon sequestration, and a slew of marine terminals for exporting hydrogen-packed ammonia to global markets. Best of all, perhaps, the region has the human capital to make a new energy hub happen — heck, look at the infrastructure and markets the folks and companies between Freeport and Lake Charles have already developed for crude oil, natural gas and NGLs. In today’s RBN blog, we begin a detailed look at the federal government’s push to advance clean hydrogen as a fuel of the future and the Houston-led effort to make the western Gulf Coast a buzzing center of hydrogen-related activity.
In the next few days, U.S. Energy Secretary Jennifer Granholm will hold an emergency meeting with leading energy executives to discuss steps E&Ps and refiners could take to increase crude oil production, refinery capacity and the production of gasoline, diesel and jet fuel, all with the aim of reducing prices. The prelude to the get-together was less than ideal, though. In a June 14 letter to the top brass of four integrated oil and gas giants and three large refiners, President Biden criticized them for “historically high refinery profit margins” and for shutting down refining capacity before and then during the pandemic. In addition to rejoinders from the companies, the American Petroleum Institute (API) and the American Fuel & Petrochemical Manufacturers (AFPM) defended their actions, discussed the complexity of refined products markets, and asserted that the Biden administration’s statements and policies have actually discouraged investment in refining and oil and gas production. Is there a middle ground here? In today’s RBN blog, we look at the high-level correspondence and discuss how at least some compromises might be possible.
If you want to get the energy world’s full attention, give it a global pandemic, a rush to decarbonize, and a brutal land war in Europe — all in quick succession. Bam! Bam! Bam! The past two-plus years have shaken the global oil, natural gas and NGL markets to the core, and forced just about everyone involved to rethink the expectations and plans they had before everything seemed to unravel. So what happens next? How do we provide energy security, put a lid on inflation, and save the planet? To answer those questions, a good place to start is to gain a better understanding of the fundamentals — how energy markets develop, work and interact. In today’s RBN blog, we discuss highlights from RBN’s recent School of Energy, a like-you-were-there replay of which is now available.
For several years now, no single topic has caused more angst in refiners’ quarterly earnings calls than the seemingly arcane topic of renewable identification numbers, or RINs, which can have a big impact on a refiner’s financial performance. RINs are a feature of the federal Renewable Fuel Standard (RFS), which requires renewable fuels like ethanol and bio-based diesel to be blended into fuels sold in the U.S. And depending on your point of view — farmer, refiner, blender, consumer, politician — you may have a very different perspective regarding RINs’ role as a tax and a subsidy. In today’s RBN blog, we dig into the fundamental aspects of RINs at the root of this long-running controversy and examine the role of RINs as a mechanism for forcing renewables into fuels.
Freeport LNG is expected to be offline for an extended period following last week’s explosion and fire at the export terminal, leaving the global gas market even more undersupplied than it already was. The outage cuts U.S. export capacity by about 2 Bcf/d at a time when Europe is still taking in huge volumes of LNG to offset declines in Russian supplies and bolster storage ahead of winter. This is all happening as another large exporting nation, Australia, is facing a critical winter energy crisis of its own and South American demand is headed toward its seasonal high, straining an already tight market. Today’s RBN blog continues our series about the ongoing Freeport outage, this time looking at the impact to the global gas and LNG markets.
Before the bullish winter of 2021-22, it appeared the Northeast natural gas market was headed for familiar territory: worsening seasonal takeaway constraints and deeper, constraint-driven price discounts starting as early as this spring. Instead, the market went in the other direction the past few months. Takeaway utilization out of Appalachia has been lower year-on-year and, for the most part, Appalachian supply basin prices have followed Henry Hub higher even as that benchmark rocketed to 14-year highs. That’s not to say that constraints out of the Northeast aren’t on the horizon. But the market is now poised to escape the worst of it this year, despite the completion of the last major takeaway pipeline project in the region, Mountain Valley Pipeline (MVP), being pushed out another year or longer, if it crosses the finish line at all. In today’s RBN blog, we provide an update on regional fundamentals and what recent trends mean for gas production growth and pricing in the region.
The Russian war against Ukraine has focused Europe on the issue of energy security, especially as it relates to natural gas. The continent has previously relied on Russia for more than 40% of its gas, but it now must scramble for new suppliers and alternative forms of energy. The matter is particularly urgent in a few countries along or very near the Russian border, including Lithuania, Poland and Ukraine itself. Fortunately, almost two years ago the three countries formed the “Lublin Triangle,” an alliance of sorts with the aim of enhancing military, cultural and economic cooperation while also supporting Ukraine’s prospective integration into the European Union and NATO. In today’s RBN blog, we discuss the potential for developing a “New Gas Order” in Europe.
An explosion June 8 at Freeport LNG, the 15.3 MMtpa (2 Bcf/d) export terminal on Quintana Island, TX, has knocked it offline at a time when the global market is already facing tight conditions because of the war in Ukraine and other factors. The explosion, fire and subsequent shutdown — which fortunately did not include any injuries — sent U.S. natural gas tumbling off recent highs and shot global gas prices higher. Much is still unknown about the developing situation, including exactly how long the outage will last. While Freeport has said it expects the terminal to be offline for at least three weeks, multiple regulatory agencies have investigations underway and will likely need to approve a return to service. In today’s RBN blog, we look at the latest news from Freeport LNG and run through the potential market implications, starting with impacts to the U.S. gas market.
California faces a broad set of challenges when it comes to reducing wildfires, which have been increasingly frequent and intense over the last decade — impacting the lives of those dealing with the threat, not to mention effects on the economy and environment. Separately, the state has been working to reduce transportation-related pollution and incentivize the development and use of a wide array of alternative fuels. Yosemite Clean Energy (YCE), which announced plans for its first plant site in late 2021, has an approach it says will not only make the state a cleaner and safer place but also foster the development of new transportation fuels. In today’s RBN blog, we look at YCE’s plans to turn wood waste into renewable fuels, how its unique “Stump to Pump” approach relies on partnerships with local communities, and the green hydrogen and renewable natural gas it plans to produce at sites across California.
We’ve written a lot lately about how U.S. E&Ps, whipsawed over the last decade by extreme price volatility and negative investor sentiment, have adopted a new fiscal discipline that de-emphasizes production growth and prioritizes generation of free cash flow to reduce debt and reward shareholders. But what about midstreamers? They too have been buffeted in recent years by volatile commodity prices, eroding investor support, shifting upstream investment patterns, and finally, a global pandemic. Midstream companies face a different set of challenges than oil and gas producers in repairing their balance sheet and restoring investor confidence, however, mostly because midstream investment decisions are determined both by downstream market changes and by E&Ps’ development and production activity — including producers’ ever-increasing focus on the Permian at the expense of other basins. In today’s RBN blog, we discuss highlights from RBN and East Daley’s Spotlight Report on Western Midstream Partners and how the master limited partnership has been working to reduce its debt and make the most of its strong base in the Permian’s Delaware Basin.