

Over the past three-plus years, Corpus Christi has dominated the U.S. crude oil export market, largely because of the availability of straight-shot pipeline access from the Permian to two Corpus-area terminals at Ingleside — Enbridge Ingleside Energy Center (EIEC) and South Texas Gateway (STG) — that can partially load the huge 2-MMbbl VLCCs (Very Large Crude Carriers). But capacity on the pipes to Corpus is now nearly maxed out and, with Permian production rising and exports strong, an increasing share of West Texas crude output is instead being sent to Houston on pipelines with capacity to spare. The catch for Permian shippers with capacity on Permian-to-Houston pipes is that the Midland-to-MEH (Magellan East Houston) price differential for WTI has been depressingly low —$0.22/bbl on average this year, compared to almost $20/bbl for a few months in 2018 and averaging $5.50/bbl as recently as 2019. However, the Midland-to-MEH WTI price spread looks to be on the verge of a rebound of sorts, as we discuss in today’s RBN blog.
Analyst Insights are unique perspectives provided by RBN analysts about energy markets developments. The Insights may cover a wide range of information, such as industry trends, fundamentals, competitive landscape, or other market rumblings. These Insights are designed to be bite-size but punchy analysis so that readers can stay abreast of the most important market changes.
November WTI fell slightly on Monday, settling at $89.68/bbl, a decrease of $0.35/bbl (-0.4%). The minor slide was attributed to Russia easing its recent fuel export ban, which had led to the perception of tightening supplies.
A Gulf of Mexico lease sale scheduled for September 27 will include millions of acres that had been removed from the sale in August by the Bureau of Ocean Energy Management (BOEM), a federal judge ruled late last week.
Report | Title | Published |
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TradeView Weekly Data | TradeView Weekly Data - September 22, 2023 | 3 days 10 hours ago |
TradeView Daily Data | TradeView Daily Data - September 22, 2023 | 3 days 13 hours ago |
NATGAS Billboard | NATGAS Billboard - September 22, 2023 | 3 days 19 hours ago |
Chart Toppers | Chart Toppers - September 22, 2023 | 3 days 23 hours ago |
TradeView Daily Data | TradeView Daily Data - September 21, 2023 | 4 days 12 hours ago |
In the last 12 months, U.S. natural gas prices have touched highs not seen since the start of the Shale Revolution as well as depths previously plumbed only briefly during downturns in 2012, 2016 and 2020. Where will prices go next? Well, if we knew that, we wouldn’t be writing blogs. As we’ve seen in the past couple of years, there’s just too much going on in global markets to think you can know where gas prices will be 10 years, five years or even one year from now. But that never stopped us from trying. As we’ve done many times before, we’ll take a scenario approach — a high case and a low case. In today’s RBN blog, we’ll explore these scenarios for domestic natural gas prices and what sort of ramifications each would entail for other markets.
U.S. production of hydrogenated renewable diesel (RD), which is made from soybean oil, animal fats and used cooking oil, is growing faster than expected. That may sound like good news for the renewable fuels industry, but it comes with the fear that the rapid growth might push RD production levels well past the mandates set by the Renewable Fuel Standard (RFS), potentially triggering a sudden crash in Renewable Identification Number (RIN) prices that — if it happens — would rock the market. In today’s RBN blog, we estimate the likelihood and possible timing of such a market-shaking event.
The global push to slash methane emissions from natural gas-related operations — from production wells to end-users — and certify gas as being “responsibly sourced” has been accelerating and broadening. It now seems possible that within the next two or three years the majority of gas produced in the U.S. will be certified as responsibly sourced gas, or RSG, and that large numbers of gas buyers — power generators, industrials, LNG exporters and local distribution companies (LDCs) among them — will be buying RSG, or at least moving toward doing so. Further, an RSG market is developing (a handful of trading platforms have already been launched), as are tracking systems to ensure that gas sold as RSG is fully accounted for and legit, with no double-counting or fuzziness. In today’s RBN blog, we begin an in-depth look at RSG and its emergence from a relative novelty to the cusp of wide acceptance.
It took an “Act of Congress” and a decision from the highest court in the land — handed down by the Chief Justice no less — but it’s looking more and more like Mountain Valley Pipeline (MVP) will be completed as early as by the end of this year, opening up 2 Bcf/d of new takeaway capacity for the increasingly pipeline-constrained Appalachian gas supply basin. That’s shifted the industry’s gaze to bottlenecks downstream of where the bulk of the volumes flowing on the new pipeline will land — on the doorstep of Williams’s Transco Pipeline in southern Virginia. A number of midstream expansions have been announced to capture the influx of natural gas supply from MVP and shuttle it to downstream markets in the Mid-Atlantic and Southeast regions, and indications are that more will be announced and greenlighted in the coming months. These projects will be key to both enabling gas production growth in the Appalachia basin as well as meeting growing gas demand in the premium markets lying on the other side of the constraints. In today’s RBN blog, we delve into the details and timing of the announced expansion projects vying to increase market access to MVP supply.
It’s only natural that deals like Chevron’s $7.6 billion acquisition of PDC Energy and ExxonMobil’s $4.9 billion purchase of Denbury grab the market’s attention. After all, the buyers are names known to everyone — even those who only think about hydrocarbons when they’re filling up at their local gas station. But a lot of other, lower-profile M&A action is happening too, especially in the Permian and also in the Eagle Ford. You might say these are cases of “Eat or be eaten” — or, in one recent case, “Eat and be eaten.” In today’s RBN blog, we discuss the plans by Permian Resources to acquire Earthstone Energy; Civitas Resources to buy assets in the Permian’s Delaware and Midland basins from Tap Rock Resources and Hibernia Resources, respectively; and SilverBow Resources to scoop up Chesapeake Energy’s last remaining assets in the Eagle Ford.
In the last 12 months, U.S. natural gas prices have touched highs not seen since the start of the Shale Revolution as well as depths previously plumbed only briefly during downturns in 2012, 2016 and 2020. Where will prices go next? Well, if we knew that, we wouldn’t be writing blogs. As we’ve seen in the past couple of years, there’s just too much going on in global markets to think you can know where gas prices will be 10 years, five years or even one year from now. But that never stopped us from trying. As we’ve done many times before, we’ll take a scenario approach — a high case and a low case. In today’s RBN blog, we’ll explore these scenarios for domestic natural gas prices and what sort of ramifications each would entail for other markets.
Given all the recent attention, you’d think the prospects for carbon-capture project development are fantastic. In the U.S., last year’s Inflation Reduction Act (IRA) featured significant increases in the 45Q tax credit for carbon sequestration, improving the economics for a wide range of carbon-capture projects. On a global level, it seems clear that efforts to reduce greenhouse gas (GHG) emissions and reach a net-zero world will continue for a long time to come. Nearly every plan to reach that target includes a significant reliance on carbon capture, with the International Energy Agency (IEA) forecasting that 7,600 million metric tons per annum (MMtpa) of carbon dioxide (CO2) — that’s 7.6 gigatons per year — will need to be captured and sequestered by 2050. We are a long way from those levels, given that most estimates put global carbon-capture capacity at a little more than 40 MMtpa today, or less than 1% of what the EIA thinks we’ll need in less than 27 years. In today’s RBN blog, we look at the main factors holding back the wider commercialization of carbon-capture initiatives in the U.S.
As this brutally hot summer meanders towards Labor Day, we’re all facing rising gasoline prices as we head to the beach, to barbecues, or to the mall for back-to-school shopping. The main culprit is crude oil production cutbacks by the Russians and Saudis and the situation would likely be much more precarious were it not for strong U.S. shale output keeping gasoline prices from climbing to $5 a gallon or more — except in California, of course. Crucial to sustaining that production long-term is not just replenishing U.S. oil reserves but growing them. In today’s RBN blog, we continue our look at crude oil and natural gas reserves with an analysis of the critical issue of reserve replacement by major oil-focused U.S. producers.
There’s a lot going on in North American crude oil markets these days. Exports are running strong. Midland WTI is now deliverable into Brent (but only if it meets specs). Pipelines from the Permian to Corpus Christi are maxed out, pushing incremental production to Houston. The price differential between WTI at Midland and Houston is nearing zero. And the value of heavy Western Canadian Select (WCS) delivered to the U.S. continues to bounce all over the place. Are these unrelated, random events in the quirky U.S. physical crude market, or are they logical developments linked by the economics of refinery preferences, quality shifts, export demand, and logistics? As you might expect, we think it’s the latter. Believe it or not, crude markets sometimes do behave rationally — and, from time to time, even predictably. That’s what we explore in today’s RBN blog.
With the Mountain Valley Pipeline (MVP) project clearing some major legal hurdles in recent weeks and construction resuming, it’s become increasingly likely that Appalachian gas producers will soon have 2 Bcf/d of new takeaway capacity, potentially as early as late 2023. However, the degree to which the pipeline will translate into higher production from the supply basin and improved supply access for the gas-thirsty, premium markets in the Southeast will largely depend on the availability of transportation capacity downstream of MVP. As such, the race is on to expand pipeline capacity from the pipe’s termination point at Williams’s Transco Pipeline Station 165 in southern Virginia, not only to deal with the impending influx of supply from MVP but also to move that gas to growing demand centers in Virginia and the Carolinas. MVP’s lead developer, Equitrans Midstream, is hoping to build an extension to the mainline — the MVP Southgate project — while Transco has designs of its own for capturing downstream customers. In today’s RBN blog, we provide an update on MVP and the various expansion projects in the works to move newly available supply to market.
The world consumes about 100 MMb/d of liquid fuels, which are critically important to every segment of the global economy and to nearly every aspect of our daily lives. The size and scope of this market means it’s impacted by all kinds of short-term forces — economic ups and downs, geopolitics, domestic developments and major weather events, just to name a few — some of which are difficult, if not impossible, to foresee. But while these events can sometimes come out of nowhere, there are some long-term forces on the horizon that will shape markets in the decades to come, even if the magnitude of these changes might be up for debate. One is a move to prioritize alternative fuel sources rather than crude oil, but a meaningful shift won’t happen as quickly as many forecasts would indicate — and that has big implications for liquid fuel demand and the outlook for U.S. refiners. In today’s RBN blog, we discuss these issues and other highlights from the recent webcast by RBN’s Refined Fuels Analytics (RFA) practice on their newly released update to the Future of Fuels report.
Over the past four years, Energy Transfer (ET) has completed several major acquisitions, all aimed at giving the company the additional size and reach it will need to compete in an increasingly consolidated midstream sector. On Wednesday, ET announced one of its biggest purchases yet: a $7.1 billion deal to acquire Crestwood Equity Partners, which has extensive gathering and processing assets in the Permian, Powder River and Williston basins, as well as NGL terminal and storage facilities east of the Mississippi. In today’s RBN blog, we look at how the addition of Crestwood’s holdings will extend ET’s value chain and complement its fractionation assets at Mont Belvieu and its export capabilities at both its Nederland and Marcus Hook terminals.
Venture Global reached a final investment decision (FID) on Plaquemines LNG Phase 1 in March 2022, making it the first new LNG project to get the green light post-COVID and kicking off a massive expansion period for U.S. LNG. In fact, more than 61 million tons per annum (MMtpa) of new U.S. LNG capacity has been given the go-ahead in the past 17 months, including the full 20-MMtpa Plaquemines LNG project from Venture Global, plus projects from Cheniere, Sempra and, most recently, NextDecade’s Rio Grande LNG. Even if no new LNG projects are sanctioned after this — which seems unlikely, given the progress seen on some pre-FID projects — the U.S. will have the capacity to export 167.5 MMtpa, or more than 22 Bcf/d, by later this decade. This unprecedented level of buildout continues to be dominated by our “Big Three” of U.S. LNG — Cheniere, Sempra and Venture Global — which not only already operate LNG export terminals in the U.S. and have projects currently under construction, but all still have more capacity under development and working toward eventual FIDs. In today’s RBN blog, we wrap up our series with a look at the newest member of the Big Three, Venture Global, its projects under development and the controversy surrounding the commissioning of Calcasieu Pass LNG.
It may be hard to believe, given the furnace-like temperatures that many of us have been dealing with the past few weeks, but the 2023-24 propane heating season is on the horizon — its official start is October 1, only seven weeks away. To quote Bill and Ted from their Excellent Adventure movie franchise, it could be argued that, for the U.S. propane market, “The best place to be is here. The best time to be is now.” Production is at or near an all-time high — so are exports. Propane inventories are well above their five-year average, which should help ward off winter-supply concerns. And propane prices? They’re up from where they were a few weeks ago, but only in the 70-cents/gal range, well below the $1/gal-plus levels that were the norm between Q3 2021 and Q3 2022. The temptation may be to yell, “Party on, dudes!”, but as we discuss in today’s RBN blog, the reality is, the propane market is an ongoing and unpredictable adventure, and you never know for sure what’s ahead.
Just a couple of years ago, TC Energy finally threw in the towel on its long-planned, long-delayed Keystone XL pipeline project, which would have substantially increased the flow of Western Canadian heavy crude to Gulf Coast refineries and export docks. It was a bitter loss. Since then, however, two other companies headquartered north of the 49th parallel have assumed leading roles in the U.S. crude oil market or, more specifically, crude exports. First, Enbridge acquired the U.S.’s #1 oil export terminal — now called the Enbridge Ingleside Energy Center (EIEC) — and related assets for US$3 billion and then, on August 1, Gibson Energy announced that it had closed on the US$1.1 billion purchase of the nearby South Texas Gateway (STG), which is #2 in crude export volumes. In today’s RBN blog, we discuss the increasing role of Canada-based midstream companies along the South Texas coast.