Natural gasoline is the most expensive natural gas liquid (NGL), accounting for more than 25% of the price-weighted NGL barrel (versus 10%-12% of the barrel by volume). It is also notoriously difficult to track, with similar products having different names and unclear demand segments. In fact, the difficulty tracking portions of demand, combined with an ongoing imbalance in crude oil supply/demand, led the Energy Information Administration (EIA) to change the way it accounted for natural gasoline demand, which made more than 200 Mb/d of production “disappear” in 2022. In today’s RBN blog, we look at natural gasoline’s primary uses and what was behind the EIA’s decision.
condensate
Friday, 4/11/2025
It’s the most expensive NGL, accounting for more than 25% of the value of a weighted average barrel. It is the only NGL that does not require storage or transportation under pressure. And it’s the most misunderstood of the NGLs, going by different names depending on the market and geography, with a chameleon-like characteristic that allows it to be transformed into various products. And to further complicate matters, other petroleum liquids are similar to natural gasoline, but not identical. In today’s RBN blog, we’ll delve into the mysteries of natural gasoline and explore what makes it such a crucial component of the hydrocarbon landscape.
Friday, 2/14/2025
Wells operated by a half-dozen E&Ps in eastern Ohio’s Utica Shale are now churning out more than 100 Mb/d of superlight crude oil — aka condensate — more than twice as much as they were just three years ago, and there’s talk that condensate production in the play’s “volatile oil window” could increase significantly over the next few years. This surge in condensate output raises three relevant questions: (1) how is the condensate being transported to market, (2) where is it headed and (3) what is it being used for? In today’s RBN blog, we continue our series on Utica condensate with a look at the approaches used to transport the commodity to refineries and others in the Midwest and points beyond.
Friday, 1/24/2025
Condensate production in the Utica Shale’s volatile oil window in eastern Ohio has more than doubled over the past three years, and plans by the handful of E&Ps that focus on the super-light crude oil suggest that output will increase further this year and next. Who are these producers, why do they see such promise for condensate growth in the Utica, and how are they measuring their success? In today’s RBN blog, we continue examining rising condensate production in eastern Ohio with a look at the leading E&Ps in this space.
Friday, 1/03/2025
The Marcellus/Utica is a natural-gas-and-NGLs play, right? Almost entirely, yes. But a handful of dogged, innovative E&Ps have been producing fast-rising volumes of superlight crude — better described as condensate — in the Utica Shale’s “volatile oil window” in eastern Ohio. In today’s RBN blog, we discuss recently ramped-up drilling-and-completion activity in that swath of the Buckeye State, the potential for more growth through the second half of the 2020s, and the impact of increasing output on Midwest midstreamers and refiners.
Tuesday, 4/11/2023
It would be an understatement to say we’re sensing a trend here. Over the past couple of years, there’s been an absolute frenzy of producer M&A activity in the Permian, much of it involving big E&Ps getting bigger and private equity cashing in on assets they’ve been developing since the 2010s. The latest multibillion-dollar deal involves Ovintiv, whose recently announced plan to acquire the Midland Basin assets of three EnCap Investments-backed producers will nearly double Ovintiv’s oil and condensate output in West Texas, lower its per-barrel production costs, and add more than 1,000 well locations to its inventory. Oh, and via a separate but related deal, Ovintiv will exit the Bakken by selling its assets there to another EnCap affiliate. In today’s RBN blog, we look at what the M&A artist formerly known as Encana is up to.
Monday, 3/13/2023
The wave of M&A activity in South Texas apparently hasn’t crested yet. Over the past couple months, Chesapeake Energy announced two deals totaling $2.825 billion that will almost complete its planned departure from the Eagle Ford — and signal UK-based INEOS’s arrival in the basin and a more than doubling of WildFire Energy’s production there. Just as important, Western Canada’s Baytex Energy a few days ago unveiled a $2.5 billion plan to acquire Ranger Oil, a pure-play Eagle Ford E&P, and thereby triple its South Texas production and gain its first operating capability in the U.S. And international interest in the basin doesn’t end there — Spanish energy giant Repsol, which had previously acquired the share of an Eagle Ford partnership held by Norway’s Equinor, recently bought basin assets held by Japan’s INPEX. (How’s that for multi-national M&A?) In today’s RBN blog, we discuss the latest round of E&P acquisitions and sales in South Texas, where production has been on the rebound.
Monday, 11/14/2022
Way back in 2015, the Eagle Ford Shale in South Texas was big news, duking it out with the Permian and the offshore Gulf of Mexico for the #1 spot in crude oil production and with the then-preeminent Haynesville for top honors in natural gas output. But the mid-decade crash in oil and gas prices hit the Eagle Ford harder than any other U.S. production area — in fact, production there remains below its peak seven years ago. Lately, however, M&A activity in the shale play has been surging, suggesting that the Eagle Ford may finally be on the verge of a serious, sustained comeback. In today’s RBN blog, we discuss this renewed interest in South Texas and whether this time the play’s recovery is for real.
Sunday, 11/13/2022
Infrastructure constraints in the energy sector come in all shapes and sizes, and don’t think for a second that they only involve pipelines. For many producers of crude oil, refined products and other liquids, the Mississippi River is a critically important conduit for barging commodities to market. Lately though, water levels on sections of the river have been near historic lows, reducing both the volume of liquids that each barge can carry and the number of barges the Mississippi can handle. Among other things, the low water situation has been putting a squeeze on condensate producers in the “wet” Marcellus/Utica, who depend on barges to transport a significant portion of their superlight crude oil down the Ohio and Mississippi rivers to refineries and for blending into Light Louisiana Sweet (LLS). In today’s RBN blog, we discuss the situation.
Tuesday, 1/11/2022
With Alberta’s bitumen production rising to record levels of late, finding more ways to export this molasses-like heavy oil has become more important than ever. In early 2020, Gibson Energy and US Development Group embarked on the construction of a diluent recovery unit in Hardisty, AB, to greatly reduce the need for diluent and retain more of it for reuse. With the unit’s commercial start-up at the end of 2021, another unique pathway for transporting Canadian bitumen to the U.S. Gulf Coast — and, possibly, overseas markets — has become a reality. In today’s RBN blog, we provide an update on this venture and discuss where it might lead next.
Wednesday, 12/16/2020
As bitumen production in Alberta’s oil sands has grown over the past decade, so has demand for diluent, which is blended with molasses-like bitumen to help it flow through pipelines or be transported by rail. With bitumen output expected to continue rising through the first half of the 2020s, we have estimated that Alberta demand for field condensate, natural gasoline and other diluent will increase by more than 40% — to almost 1 MMb/d — by 2025. The catch is, diluent production in Western Canada isn’t growing fast enough to keep pace, and there are limits to how much diluent can be imported on the two existing pipelines from the U.S. What if there were a way to slash how much diluent is needed to put bitumen in rail tank cars — and make rail transport safer in the process? Today, we discuss Gibson Energy and US Development Group’s new diluent recovery unit in Hardisty, AB.
Sunday, 11/01/2020
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.
Sunday, 9/27/2020
Canadian gas production in 2019 turned lower for the first time in half a dozen years as very weak benchmark Canadian gas prices led to a sharp reduction in drilling and wellhead shut-ins. This year, higher prices, more drilling, and greater pipeline egress capacity were supposed to set the stage for a return of supply growth. Instead, production volumes have slipped further due to reduced drilling activity and, more recently, a spate of maintenance work. And even if there is some improvement in the next few months, annual average production looks to be on track for a second consecutive decline in 2020. But what about next year? Today, we take a closer look at the recent supply trends and whether there are any signs pointing to a production rebound in 2021.
Tuesday, 6/23/2020
The folks who transport bitumen from the Alberta oil sands to faraway markets depend on light hydrocarbons collectively known as diluent to help make highly viscous bitumen flowable enough to be run through pipelines or loaded into rail tank cars. The catch is — or was, we should say — that Western Canada wasn’t producing nearly enough condensate and other diluent to keep pace with fast-rising demand, so a few years ago, two pipelines from Alberta to the U.S. Midwest were repurposed to allow diluent to be piped north. More recently, though, Western Canadian production of diluent has been soaring and new pipeline capacity has been built within Alberta to deliver it to the oil sands. That has the potential to reduce the need for imports from the U.S. and may soon lead to at least one of the import pipes being repurposed yet again. Today, we continue our series on diluent with a review of the pipeline systems that collect locally produced light hydrocarbons that are eventually employed in the oil sands.
Wednesday, 6/10/2020
Bitumen, the heavy, viscous form of crude oil associated with Alberta’s oil sands, has been the workhorse behind Canada’s ascent to near the top of oil-producing nations. However, it is impossible to get raw, near-solid bitumen to refiners by pipeline without either upgrading it to a flowable crude oil or blending it with lighter hydrocarbon liquids, a.k.a. diluents, to form the more diluted version of the product, referred to as “dilbit.” As for moving bitumen by rail, there are two main options: using heated tank cars or blending it with diluent to form “railbit.” The rapid rise in bitumen production in the past decade — interrupted only by wildfires and the recent price crash — has generated a large parallel market for diluents, whose fortunes are closely tied to the oil sands. U.S.-sourced diluent currently meets a substantial portion of the demand. But with Alberta oil sands development poised for renewed growth and in-province condensate production rising, the Canadian diluent market could be in for some big shifts. Today, we start a blog series considering the unique role that this special form of hydrocarbon plays in the oil sands.