Northeast natural gas production in 2021 to date has averaged 34 Bcf/d, up 1.4 Bcf/d year-on-year, and the higher gas price environment currently is signaling more upside to production in the years to come. At the same time, downstream feedgas demand from LNG export facilities is at a record high and also headed higher as more liquefaction capacity is set to come online in the coming months. So, despite lower-than-normal inventory levels in the Northeast, outflows from the Appalachian basin have soared to new highs this year, and utilization of outbound pipeline capacity is up to an average 90%, a level we haven’t seen since the 2016-17 timeframe. Unlike 2016-17, when there was a slew of major pipeline projects to expand egress, now there are just two or three at most — and two of those are greenfield projects that face an uncertain future. As such, spare exit capacity is getting increasingly sparse, and Appalachian producers are bound to hit the capacity “wall” in the next two years. When will the Northeast run out of exit capacity and how bad could constraints get? Today, we provide highlights from our new Drill Down report, which brings together our latest analysis on Northeast gas takeaway capacity and flows.
Daily Energy Blog
Supplies of natural gas liquids, especially propane, have become increasingly tight in recent months, with prices reaching multi-year highs in the U.S. and Canada. Despite the strong price signals, increasing production is typically a lengthy, complex, and expensive process involving producers drilling new wells to yield more liquids-rich natural gas and crude oil. There is also another way to increase supplies: by extracting them from already processed and pipelined natural gas via a straddle plant that more intensively recovers additional NGLs, such as propane, from the existing gas supply. Canada’s Wolf Midstream has recently sanctioned such a plant, as well as a related pipeline and extraction plant in Alberta that it hopes to bring into service in 2023. In today’s blog, we examine this new straddle plant and Western Canada’s current propane supply situation.
It’s often said that the offshore Gulf of Mexico is a different animal than its onshore counterparts, especially shale and tight-oil plays like the Permian and the Bakken. Decisions to invest in new production in the GOM aren’t based on crude oil demand and price forecast for the next two or three years; they’re based on expectations for the next two or three decades. Well, 30 years from now will be 2051, a year after Shell and a number of other energy companies have pledged to achieve “net-zero” carbon emissions. What does decarbonization mean for future development in the offshore Gulf, where the upfront capital costs are enormous and wells can be prolific producers for many, many years. In today’s blog, we discuss the final investment decision (FID) on Shell’s Whale project in the western Gulf of Mexico and the prospects for further development in the GOM.
Every day, midstream companies in North America transport massive volumes of crude oil, natural gas, NGLs, and refined products to market. Without their pipelines, economic activity would rapidly grind to a halt. Still, environmental critics and ESG-conscious investors and lenders are quick to point out that the commodities that midstreamers pipe are among the leading sources of greenhouse gas emissions, and that, at the very least, pipeline companies should be reducing or even offsetting the carbon dioxide (CO2) and other GHGs associated with operating their networks. That’s now happening in a big way — and in a variety of ways — as we discuss in today’s blog.
A couple of weeks ago, Shell announced a large-scale carbon capture and sequestration initiative at its Scotford refinery complex near Edmonton, AB. It’s one of the largest recent efforts to marry hydrogen production with CCS — an increasingly popular solution informally referred to as “blue” hydrogen. Shell is not alone. Across North America, the idea of capturing carbon dioxide to clean up our collective act is quickly gaining momentum and support. Whether we’re talking about refineries, ammonia plants, steam crackers, ethanol plants, or any other carbon-generating industrial process, capturing the CO2 — making the process “blue” — is seen by many as a way to make significant progress toward climate goals without over-burdening governments or consumers with the sky-high costs associated with some of the more technically challenging energy transition technologies. Today, we discuss the energy industry’s embrace of carbon capture solutions and how it could shape our energy future.
The EIA report on propane inventories that came out yesterday was a shocker. This time of year, stocks are supposed to be building toward the levels needed to get U.S. propane markets through the winter season. But the numbers released on Wednesday showed an inventory decline, resulting in inventory balances now below the five-year minimum. The culprit, of course, is exports, with 1.4 MMb/d of them reported last week, a 17% gain over the year-to-date average. And these cargoes to overseas markets are happening even with propane prices in the stratosphere: more than double where they stood this time last year. Propane marketers were hoping that higher prices would slow down exports, but so far that is not happening. In today’s blog, we examine U.S. exports of LPG — propane plus butane — and discuss what may be ahead for these markets.
Traveled by air in the U.S. lately? Airports and airplanes are packed to the gills. Unruly passengers are making the nightly news and becoming YouTube sensations. Jet fuel shortages are popping up. But there are other developments in air travel too, including a push by the global airline industry to rein in its greenhouse gas emissions. And the heart of that movement is sustainable aviation fuel, or SAF. While the blending of SAF with conventional jet fuel is not mandated in the U.S., the alternative fuel is gaining altitude, in part because it can generate layers of credits that can be utilized in various renewable fuel trading programs. In today’s blog, we look at the current status of renewable fuel in the U.S. aviation sector.
The law of unintended consequences may be about to play out in society’s quest to sequester — or permanently store underground via enhanced oil recovery and other means — the carbon dioxide captured at ethanol plants, power generators, and other industrial facilities in the U.S. Why? Well, there are many legitimate, important uses for that manmade CO2, including in food processing and beverage making, among other industries, and diverting large volumes of captured CO2 from them to EOR and other sequestration methods due to highly attractive government incentives may put the squeeze on CO2 supply and send prices soaring. No one said that saving the planet would be easy or uncomplicated. In today’s blog, we discuss a possible hitch in the push to reduce greenhouse gas emissions and how it might be dealt with.
Carbon-neutral hydrocarbons may sound like an oxymoron, but an increasing number of international shippers have been assembling and sending out cargoes of LNG whose expected lifecycle carbon-dioxide (CO2) emissions have been fully offset by carbon credits. What’s next? No-calorie cherry pie? No-loss gambling on DraftKings? A winning season for the Houston Texans? (Probably not.) As you’d expect, carbon-neutral cargoes of LNG — and crude oil and LPG — are designed to help hydrocarbon sellers and buyers alike meet their goals for reducing their greenhouse gas emissions (GHGs). The concept is still relatively new, though, and many of the participants in these deals are still in learning mode, seeking to gain experience with something they expect to see a lot more of soon. In today’s blog, we discuss the relatively short history of this type of shipment and the first signs that carbon-neutral hydrocarbons are about to go mainstream.
If you’re a relative newcomer to the energy industry, the subject of natural gas storage might make your eyes glaze over — the sector is often treated as a backwater by traders and investors focused on liquid hydrocarbons. But it wasn’t always so. In the decades leading up to the early 2000s, the U.S. gas market underwent a series of fundamental changes, each spurring the development of new storage capacity, first in the Northeast, then the Midwest, and finally along the Gulf Coast. Along the way, the primary use of storage — balancing seasonal swings in gas demand — remained consistent, but there was also a wild-and-woolly period in the mid-2000s that was rife with meme-stock-like trading frenzy. It’s hard to say for sure, but we may be on the verge of needing still more gas storage capacity. In today’s blog, we’ll discuss the history and nature of U.S. natural gas storage to give context on what the future might hold.
Although it’s not well publicized, Canada’s oil and gas sector is already a global leader in active projects targeting significant reductions in greenhouse gas emissions, primarily carbon dioxide. These successes — some dating back as far as Y2K — are being used as a springboard for additional projects, all aimed at helping Canada achieve its aggressive GHG-reduction goals for 2030 and beyond. The scale of many of these projects is noteworthy. In today’s blog, we discuss the existing operations and planned projects that together will help the U.S.’s northern neighbor reduce its carbon footprint.
For some time now, a handful of refineries in southeastern Louisiana, Mississippi, and Alabama have been able to receive steeply discounted, heavy sour crude from Western Canada by rail or barge — or, in rare cases, by pipeline from Cushing to Nederland, TX, to the St. James, LA, hub. Starting in a few months, though, this same crude also will be able to flow by pipe directly from Patoka, IL, to St. James on the soon-to-be-reversed Capline pipeline. Initially, the southbound volumes on Capline will be modest, but over time they could increase to several hundred thousand barrels a day. Will those barrels be loaded onto supertankers and shipped overseas, or will they be headed for refineries in Louisiana and its eastern neighbors? In today’s blog, we try to answer those questions.
What if crude oil could be extracted from the ground, refined into gasoline and diesel, trucked to your local service station, and used in your SUV to take that next road trip, all the while resulting in LESS CO2 being emitted into the atmosphere? That would mean carbon-negative crude. Crazy talk from a relic of the fossil (fuel) generation? Not so! Carbon-negative crude is being produced today along the U.S. Gulf Coast, assuming you buy the logic of how carbon accounting works for capturing CO2 and using it for enhanced oil recovery — EOR. In today’s blog, we’ll explore what it takes to achieve carbon-negative crude, and why there is vast potential for expanding this pathway to lower greenhouse gas emissions.
In case you hadn’t noticed, there’s a big push by the government, industry, and the broader public to reduce greenhouse gas (GHG) emissions and to offset those that do occur. Given its carbon-intensive nature, the oil and gas sector is at the heart of this activity, with almost daily announcements about carbon-neutral LNG shipments, carbon-dioxide capture and sequestration projects, and other efforts. The problem is, it can be difficult sometimes to figure out what’s real and what’s not — that is, which efforts have an actual, measurable impact and which are sort of vague or fuzzy and need to be sussed out. Today, we discuss the latest round of announcements by producers, midstreamers, refiners, and others to “green up” their operations and products.
Just a few years ago, Mexico was focused on importing LNG to help meet its natural gas needs, especially in parts of the country far from Permian and other U.S. supplies. Lately though, most of the talk about LNG in Mexico has been about liquefaction and/or exporting, not importing and regasifying, as evidenced by a final investment decision on the Energía Costa Azul liquefaction project in Baja California and progress on Mexico Pacific Ltd.’s liquefaction/export project in Mexico’s Sonora state. Both projects are aimed squarely at Asian markets, but yet another prospective LNG project “south of the border” is targeting bunkering, transportation, and industrial markets for natural gas along the Pacific side of Latin America — from Mexico itself down to Ecuador. In today’s blog, we discuss plans for what could be Mexico’s third major liquefaction project — this one aimed at both domestic and export markets.
