For the past several years, Western Canada’s natural gas producers have been forced to sit on the sidelines of too many broader price rallies as their main benchmark, AECO, languished at painfully low levels. Though an increasing number of producers have been steadily diversifying their price exposure away from Western Canada and AECO, even greater pricing upside might be captured if marketing arrangements could be developed to access higher international LNG prices via U.S. Gulf Coast terminals. In today’s RBN blog, we look at the steps that two of Canada’s largest natural gas producers have taken to capture that LNG price upside.
Daily Energy Blog
We can’t conjure up a more old-school, more intrinsically American industry than whiskey-making, or more iconic whiskey names than Jack Daniel’s and Jim Beam — the latter, of course, being a bourbon, a particular type of whiskey. The recipes for both “Jack” and “Jim” have remained unchanged for generations and their distillers in Tennessee and Kentucky, respectively, are traditionalists to their core. That doesn’t mean, though, that they’re unaware of the need to reduce their greenhouse gas (GHG) emissions — or are blind to the opportunities that decarbonization may present. Now, as we discuss in today’s RBN blog, both Jack Daniel’s and Jim Beam are all-in on producing renewable natural gas (RNG) from spent grains.
If you buy premium gasoline, you’ve probably noticed its price differential versus regular has been increasing in recent years. That is a sign of the rising value of octane, the primary yardstick of gasoline quality and price. In this blog series we’ve examined a new gasoline sulfur specification called Tier 3, which is causing complications for U.S. refiners looking to balance octane and gasoline production while still meeting the regulatory limits on sulfur. In today’s RBN blog, the fourth and final on this topic, we provide an analysis of the obscure Sulfur Credit Averaging, Banking and Trading (ABT) system, which allows refiners to buy credits to stay in compliance with the Tier 3 specs. The price of these credits quintupled in 2022, another sign of a tight octane market that will be attracting increased attention in the months and years ahead.
New, stiffer rules on well siting, drilling and production undoubtedly pose potential challenges to producers. After all, these changes typically impose further limits on what E&Ps can do on the acreage they control as well as new requirements. But like death and taxes, environmental regulation is a certainty that producers need to deal with and, if they’re lucky, they can find a way to work with new rules and minimize their impact on their businesses. That seems to be what’s happening in Colorado — home to the rebounding Denver-Julesburg (DJ) Basin and other production areas — which enacted a new oil and gas permitting law a couple of years ago and subsequently developed and implemented related regulations. As we discuss in today’s RBN blog, most producers seem to have figured out how to manage the new regs.
Sixty percent of crude oil produced in the U.S. is exported, either as crude or in the form of gasoline, diesel, jet fuel or other petroleum products. Sure, a lot of crude and products are still imported, but the net import number is dwindling toward zero — and if you throw NGLs into the liquid fuels balance, the U.S. has been a net exporter since 2020. Yes, exports are now calling the shots in U.S. liquid fuel flow patterns, price differentials, infrastructure utilization and, to a great extent, the winners and losers in crude oil and product markets. It’s going to get way more intense as export economics increasingly dominate which pipelines, refineries and port facilities capture production growth from the Permian and other basins. In today’s RBN blog, we begin a series to explore this revolutionary shift in fortunes, why barrels move where they do and what it all means for U.S. producers, midstreamers, refiners, marketers, and exporters. And a warning! This is a subliminal advertorial for our upcoming xPortCon-Oil conference.
With the war in Ukraine ongoing and Europe largely cut off or quitting Russian natural gas imports, many feared that global gas prices would skyrocket this winter, but prices have fizzled out instead and are at their lowest level since September 2021. That’s not to say gas prices are low, as they are still well above historic norms and high enough to incentivize LNG imports and the development of future LNG capacity. But despite losing its largest gas supplier, and prices running up in the months ahead of this winter, Europe appears to be in much better shape than it was last winter and gas prices have been relatively calm and on the downswing. So why is that? The difference between this winter and last largely boils down to storage inventories and the ability to attract LNG cargoes. In today’s RBN blog, we look at the European gas market, the impact of U.S. LNG supplies, and what it all means for developing LNG projects.
If the world is going to reduce greenhouse gas (GHG) emissions to net-zero levels by 2050, a lot of things need to go right, with the success of the International Energy Agency’s (IEA) long-term plan balancing on three different pillars. First, there are emissions reductions from improvements to fossil fuels and processes, such as power generation and industrial production. Next, there are advancements in bioenergy, a category that includes biofuels like ethanol, sustainable aviation fuel (SAF), and renewable diesel (RD). And then there’s direct air capture (DAC) — a minor factor so far, but one with the potential for significant growth, especially given the billions in U.S. funding already set aside for it. In today’s RBN blog, we look at U.S. plans to develop four regional DAC hubs, how those proposals will be evaluated, and the likely timeline for their development.
What’s the fastest-growing U.S. hydrocarbon? You guessed it — ethane. Since 2016, ethane production has grown at almost 2.5 times the rate of crude oil or natural gas and 1.5X that of other natural gas liquids (NGLs). And there’s a lot more upside potential where that came from. It’s entirely demand-pull, meaning that U.S. ethane production growth is being driven by increasing domestic and export demand for the petrochemical feedstock. Shell’s new steam cracker in Pennsylvania is online, CP Chem and Qatar Energy are planning a new cracker in Orange, TX, and other projects are in the works. On the exports front, both Enterprise and Energy Transfer announced export-terminal-expansion projects in 2022. All this new ethane demand needs supply, and fortunately the U.S. has the barrels, not only from ever-increasing NGL production, but also from ethane that today is being rejected and sold as natural gas. And the markets will need new pipes, fractionators, and ships to get that ethane to market. With today’s RBN blog, we begin a series to explore what these developments mean for U.S. ethane market players.
If pipeline-constrained Haynesville Shale producers’ New Year’s resolution was to grow volumes, they just got a big boost: Energy Transfer recently placed in service its new Gulf Run Transmission natural gas pipeline in Louisiana, increasing north-to-south capacity in the state by 1.65 Bcf/d. It’s the first of several pipeline projects due online in 2023 — and among others proposed for subsequent years — that will be critical for debottlenecking the Louisiana pipeline network and connecting Haynesville and other gas production volumes to LNG export projects vying for feedgas supply on the Louisiana coast. U.S. LNG developers are in a race to capitalize on the tight global LNG market and finalize terminal plans, with much of the next wave of liquefaction and export capacity additions planned for the Louisiana coast which may, in time, help alleviate energy security concerns, particularly across the pond in Europe. If these pipeline projects don’t get built on time, the resulting supply shortage in southern Louisiana would not only wreak havoc on Henry Hub and the domestic gas market but would reverberate around the globe. Gulf Run’s in-service is good news for at least one facility: the under-construction Golden Pass LNG, which is the anchor shipper on the pipeline and due to begin commissioning later this year. In today’s blog, we look at what the new capacity could mean for flows and production growth in the short- and long-term.
The U.S. has committed billions of dollars over the last couple of years to clean-energy initiatives, everything from advanced fuels and carbon-capture technology to renewable energy and electric vehicles. The “all-of-the-above” approach also includes clean hydrogen, whose development the U.S. Department of Energy (DOE) has deemed crucial to meeting the Biden administration’s goals of a 100% clean electric grid by 2035 and net-zero carbon emissions by 2050. As part of its efforts, the U.S. plans to provide generous financial support for the buildout of several hydrogen hubs — initial concept papers were submitted last year by dozens of applicants for the federal largesse, and the DOE recently provided formal “encouragement” to 33 proponents to submit a full application this spring, in what amounts to an informal cutdown, but declined to name them. In today’s RBN blog, we examine the 18 projects we’ve been able to identify that survived the trimming, what they tell us about the selection process, and how it compares to our previous expectations.
Worried about 2023? Well, you’ve got good reason to be. This year energy markets are at the mercy of a hot war in Europe, the threat of a global recession, looming China/Taiwan hostilities, the impending onslaught of new energy transition programs from recent legislation, and all sorts of other random black swans paddling around out there. With so much uncertainty ahead, predictions this year would be just crazy talk, right? Nah. No mere market murkiness will dissuade RBN from sticking our collective necks out to peer into our crystal ball one more time. Let’s hope it’s no bad bunny.
Senior refining executives were called to Washington, DC, in June, around the time U.S. gas prices hit their high-water mark for the year, as the government sought recommendations about how to increase the supply of gasoline. One suggestion made to Secretary of Energy Jennifer Granholm was to relax sulfur specifications on fuels, including the Tier 3 gasoline sulfur specifications. But what is the connection between those rules and the U.S. refining system’s ability to produce gasoline? In today’s RBN blog, we explain how the Tier 3 rules constrain gasoline supply capacity in the U.S. and discuss ways to break free from those chains.
You probably won’t be surprised to hear that we believe the Permian Basin is set for another year of crude oil and natural gas production growth. Everyone’s come to expect that from the Permian. What is new, though, is that the vast production area in West Texas and southeastern New Mexico has taken on some serious global significance over the past year — especially as an increasingly important energy supplier to Europe. That emerging role is likely not only to support continued production growth in the Permian but also to shape how the basin’s infrastructure is built out through the rest of the 2020s. And we also know that infrastructure development is critical to the Permian’s ongoing success — in 2023, new gas pipeline takeaway capacity is needed pronto and it may not be long before new oil-pipeline capacity from the Permian to Corpus Christi is required too. In today's RBN blog, we provide this year’s outlook for Permian natural gas and oil markets.
Since 2019, more than 1.3 MMb/d of U.S. refinery capacity has been either shut down for economic reasons or converted to renewable diesel production. The decline in the nation’s ability to produce gasoline and diesel hampered the refining sector’s response to the post-COVID demand recovery and exacerbated the big run-up in motor fuel prices that followed Russia’s invasion of Ukraine last February. Now, there may be a new threat to U.S. refining, namely the possibility that a proposed Environmental Protection Agency (EPA) rule on hydrofluoric-acid-based alkylation could, over time, spur an even larger round of refinery closures. In today’s RBN blog, we continue our look at alkylate — a critically important part of the U.S. gasoline pool — the prospective regulation and its possible effects.
Since the advent of the Shale Revolution way back in 2008, U.S. production of natural gas liquids from gas processing has grown pretty much non-stop, from an annual average of 1.8 MMb/d 15 years ago to 5.9 MMb/d in 2022 — a 9% compound annual growth rate. Today, NGL production exceeds 6.1 MMb/d and that number might be even higher if the glut of supply wasn’t depressing prices and discouraging the recovery of a lot of ethane. All that production has major implications for domestic pricing, upstream economics, midstream infrastructure, and downstream consumers like petrochemicals, not to mention international markets, which now receive roughly 40% of U.S. output. In today’s RBN blog, we examine what’s causing NGL production to continually increase.