RBN Energy
Early Access
Tuesday, 9/30/2025
Friday, 9/26/2025
Before data centers were the hot topic everywhere, Virginia was already rolling out the red carpet and it seemed that tech firms were constructing facilities as fast as humanly possible, drawn by the state’s robust fiber-optic network and low power prices. But while other states are racing to catch up, Virginia may be hitting the brakes. In today’s RBN blog, we’ll look at what makes Virginia so “sweet” for data center developers, their impact on the state, and efforts by some to slow progress.
Analyst Insights
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.
By John Abeln - Monday, 9/29/2025 (3:30 pm)
Report Highlight: NATGAS Permian
Dry natural gas production in the Permian Basin averaged 22 Bcf/d for the week ended September 29, down slightly from the week prior, with small changes across most pipelines in the basin last week. The past few weeks, El Paso Pipeline has been the primary driver of lower supply.
By Martin King - Monday, 9/29/2025 (2:15 pm)
For the week of September 26, Baker Hughes reported that the Western Canadian gas-directed rig count was unchanged at 60 (blue line and text in left hand chart below), five less than one year ago and is holding at its highest point since mid-March.
Daily Energy Blog
Wednesday, 6/30/2021
Category:
Crude Oil
It’s been a challenging few years — some would say decades — for producers in northern Alaska. Crude oil production in the remote, frigid region peaked at just over 2 MMb/d in 1988 and has been falling ever since, dropping to about 450 Mb/d in 2020 and the first few months of 2021. It’s not that Alaska is running out of oil; far from it. Instead, the state’s energy industry has been battered by competition from shale producers in the Lower 48, thwarted by federal policies, and, more recently, ESG-related concerns and the Biden administration’s efforts to put the kibosh on new federal leases. Despite it all, the few producers still active in Alaska hold out hope for a revival. Today, we discuss the many hurdles that northern Alaska producers face.
Tuesday, 6/29/2021
Category:
Natural Gas
Western Canada’s Montney-sourced natural gas production has been on a remarkable upward trajectory in the past decade. Most of this growth has been focused in one province: British Columbia. However, that progress has not come without difficulty. A key challenge during BC’s gas boom has been providing sufficient pipeline takeaway capacity — the hurdles include the BC Montney’s remoteness, various regulatory impediments, and the unique geologic nature of the play. For this amazing gas supply growth story to continue well into the future, more pipeline capacity needs to be constructed. In our concluding blog on the Montney, we discuss recent pipeline developments and the challenges still ahead.
Monday, 6/28/2021
Category:
Crude Oil
The vast potential for permanently storing carbon dioxide underground by using it for enhanced oil recovery can only be realized if produced or captured CO2 can be economically transported long distances via pipeline. And the only way that can happen is if the CO2 is compressed into a “supercritical” or “dense-phase” fluid — a state that is somewhat compressible like a gas but flows and can be pumped like a liquid. When CO2 is in a supercritical state, much more of it can economically flow through a pipeline to the producing field. And when it gets there, the dense-phase CO2 can be injected into an oil production zone, where it has the unique ability to flow through permeable rock formations, bond with and “swell” trapped oil molecules, and free the oil to move to the production well, then up to the surface. Given that CO2-based EOR is destined to become a much more significant activity in the energy industry, it’s time for a fun-filled review of the thermodynamics of fluids as it relates to the transportation of CO2 and its use in the production of crude oil. (Wait! Don’t leave! This will be easy to follow! We promise!) Today, we continue our series on the rapidly evolving CO2 market and why it matters to crude oil producers.
Sunday, 6/27/2021
Category:
Renewables
Renewable diesel is a popular topic in the transportation fuel space, and for good reason. For one, RD provides a lower-carbon, renewable-based alternative to petroleum-based diesel; for another, it’s a chemical twin of and therefore a “drop-in” replacement for ultra-low sulfur diesel. But, most of all, there are the large financial incentives provided by California’s Low Carbon Fuel Standard, the U.S. Renewable Fuel Standard, the U.S. Biodiesel Tax Credit, and other programs, which can make RD production highly profitable. Driven by these factors, there’s a lot of renewable diesel production capacity under construction or on the drawing board: everything from greenfield projects to expansions of existing RD refineries to conversions of old-school refineries so they can make RD. Today, we put the spotlight on RD and discuss how it differs from biodiesel, how it’s produced, and the new RD capacity coming online in North America.
Thursday, 6/24/2021
Category:
Renewables
Hydrocarbons — mostly natural gas and coal — are still the energy source behind the lion’s share of electric power generation in the U.S. However, renewables like wind and solar are now the frontrunners when it comes to scheduled capacity additions. In fact, renewables account for about 70% of the total 37.9 gigawatts (GW) of new generating capacity under construction in 2021. Recent announcements such as final federal approval for the mammoth Vineyard Wind 1 project — by far the largest permitted offshore wind project in the U.S. to date — only bolster the view that wind power’s role in U.S. power generation will continue to grow through the 2020s. Today, we look at the surge in construction of onshore and offshore wind farms and what it means for the overall power generation mix.
Wednesday, 6/23/2021
Category:
Natural Gas Liquids
Propane prices at Mont Belvieu soared above $1/gallon on Wednesday — the first time that’s happened in the month of June since 2014. This buck-and-change price doesn’t come as much of a surprise for industry insiders, however. U.S. propane inventories have been very skinny lately, sitting at 56.2 MMbbl — or only 587 Mbbl above the five-year minimum based on yesterday’s EIA data. At the same time, propane exports have been riding high, averaging 1.3 MMb/d so far this year, up nearly 90 Mb/d from the same time frame in 2020, while production has remained virtually flat over the past 18 months. Surprise or not, the spike past $1/gal raises an important question: How high will U.S. propane prices have to go before exports are reined in so U.S. inventories can increase? Today, we discuss the key drivers behind the current price level and our propane market outlook for the second half of the year.
Tuesday, 6/22/2021
Category:
Renewables
With all the hype about hydrogen you hear these days, you’d think the gas was just discovered yesterday. But, of course, it’s been around for a while — like back to the Big Bang 13.8 billion years ago. It does a nice job powering the sun and, when combined with oxygen, provides another building block of life on our planet: water. And that’s not all. For decades, a lot of hydrogen has been used as industrial feedstock to produce low-sulfur refined products, ammonia, methanol, and other useful stuff. However, this hydrogen production isn’t “green,” the color code for the highly exalted hydrogen produced from zero-carbon sources. No, most of the hydrogen used today goes by the drab hue of “gray” and is generally ignored by the carbon-neutral buzz that permeates the decarbonization dialogue. It shouldn’t be disregarded, though. Over 13 Bcf/d of this gray hydrogen is produced on purpose or as a byproduct each day, more than the volumetric equivalent of all Permian natural gas production. And if the carbon dioxide produced along with that hydrogen is stored permanently underground, then gray hydrogen magically becomes “blue” — almost as good as green. Today, we begin an exploration of the gray hydrogen market, and how it has the potential to impact decarbonization goals far more than green hydrogen over the next decade.
Monday, 6/21/2021
Category:
Natural Gas
The immense Montney Formation in Western Canada is almost equally divided between the two provinces of Alberta and British Columbia. However, on either side of the provincial border there are stark differences in the number of wells drilled, well length, well productivity, and natural gas production. All these differences have resulted in Alberta being the much smaller player in the Montney gas story, with production from its side of the formation only helping to hold the line on Alberta’s total gas output in the past few years. Today, we continue our Montney analysis by looking at gas well trends on the Alberta side of this prolific formation.
Sunday, 6/20/2021
Category:
Crude Oil
Using carbon dioxide for enhanced oil recovery offers tremendous potential for CO2 sequestration. The problem is, most the CO2 used in EOR today is produced from natural underground sources, only to be piped to EOR sites and put underground again. Realizing the full promise of CO2-for-EOR would require sourcing more and more anthropogenic CO2, or A-CO2 — in other words, “man-made” CO2 that is captured from power generation and industrial processes. In addition to the environmental benefits, there are two other drivers for making this switch from natural CO2 to A-CO2: the first is that some of the natural sources of CO2 used today for EOR are dwindling, and the second is that the push to sequester man-made CO2 is backed by tax credits and other government-backed incentives. No matter the CO2 sourcing, CO2-for-EOR requires pipelines to transport the CO2 from where it is produced to EOR sites. Today, we continue our series on the rapidly evolving CO2 market and the huge opportunities that may await those who pursue them.
Thursday, 6/17/2021
Category:
Renewables
With Environmental, Safety, and Governance (ESG) conscientiousness on the rise and the push to rein in greenhouse gas emissions gaining momentum by the day, many traditional players in the hydrocarbon sector are considering alternative energy sources to invest in. Two key questions they ask themselves when evaluating these options are: Does it make economic sense once you’ve factored in tax credits and other incentives, and can it be incorporated into North America’s existing energy infrastructure. Wind and solar power clearly fit the bill. So does renewable diesel, which also benefits from governmental programs and that it can be blended into petroleum-based diesel. Another alternative gaining traction is renewable natural gas, which is “produced” by capturing methane from landfills and wastewater treatment plants. Today, we discuss the potential and pitfalls of “the notorious RNG.”
Wednesday, 6/16/2021
Category:
Renewables
We get that the primary focus for oil and gas producers, midstream companies, and refiners needs to be on the business side of things — the strategies and capital plans they develop and implement to survive and hopefully thrive, and the day-to-day decisions they make to keep things running smoothly — and that’s what we at RBN devote most of our time to as well. Still, it seems increasingly apparent that many of these same companies need to pay more attention to environmental, social, and governance issues, not only because ESG is a front-and-center concern of investors and lenders but because addressing these issues in the right way can help to improve a company’s operations and prospects. The environmental element of ESG typically gets the spotlight, at least for companies that produce, transport, or process oil and gas, but the social and governance parts are important too.
Tuesday, 6/15/2021
Category:
Crude Oil
It’s been a mantra in the energy industry for a few years now: more Canadian and Lower-48 crude oil needs to move to the Gulf Coast, with its bounty of refineries and export docks. And that’s been happening, thanks to a slew of new and expanded pipelines and new tankage. Similarly, new export capacity has been developed, and a number of refineries in Texas and Louisiana revised their crude slates to take advantage of what looked like an ever-rising supply of North American crude. Yet another piece of the puzzle will slide into place in January 2022, when crude oil — most of it heavy Western Canadian — will start flowing south on the newly reversed, large-bore Capline pipeline from the Patoka hub in Illinois to the impressive collection of terminals in St. James, LA. Today, we continue our series on the market impacts of Capline’s upcoming reversal on St. James, Louisiana refineries and crude exports.
Monday, 6/14/2021
Category:
Natural Gas
Appetite for new North American LNG export capacity had been waning already when COVID-19 brought it to a screeching halt. The global gas market was expected to be well-oversupplied through the mid-2020s as U.S. liquefaction capacity additions, combined with supply growth from Australian LNG projects, were far outpacing any increase in demand. However, the past year or so has proven how quickly things can swing from oversupplied to undersupplied. The extended run of high global gas prices is bringing renewed interest in expanding North American LNG export capacity. Although COVID dashed the prospects of many LNG projects, a handful have emerged from the morass of the past year stronger and with a clearer path to FID than ever before. Those that remain will be better positioned if they can navigate four emerging trends that are key for offtaker agreements in the post-COVID era: shorter contract terms, increased pricing or deal-structure diversity, reduced environmental impact, and a prioritization of brownfield expansions or phased greenfield projects. Today, we conclude the series on the status of the second wave of LNG projects.
Sunday, 6/13/2021
Category:
Financial
The return of $70/bbl WTI raises an important question: With a lot more cash flowing in, will public E&Ps maintain the financial discipline they’ve tried to live by since the crude oil price crashes of 2014-15 and, more recently, the spring of 2020? We’ve said it before, but it bears repeating that many producers once prided themselves on the riverboat-gambling nature of their business but, after a major scare or two, came to adopt a far more conservative approach to investment based on their new 11th commandment: “Thou shalt live within cash flow.” Emerging from the pandemic, E&Ps’ 2021 capital investment announcements guided to maintenance-level outlays designed to maximize free cash flow for debt reduction and returning cash to shareholders through dividends and share repurchases. Still, old habits die hard, right? So, when oil prices strengthened and cash flow soared in the first few months of 2021, we wondered if producers would give in to temptation to reap short-term benefits from their accelerating output. Today, we analyze the actual first quarter cash-flow allocation of the 39 E&P companies we monitor and compare it with the deployment of cash flow in 2019 and 2020.
Thursday, 6/10/2021
Category:
Natural Gas
Of the 10 Bcf/d, or more than 75 MMtpa, of nameplate LNG export capacity currently operational in the Lower 48, Japanese companies form the largest single group lifting U.S. cargoes. Their commitments total ~2 Bcf/d of U.S. liquefaction capacity. However, Japan’s LNG consumption has been falling over the past two years, and in 2019 and 2020, U.S. LNG accounted for only 0.6 Bcf/d and 0.8 Bcf/d of Japanese imports, respectively, or about 20% of the country’s total LNG demand in each year. In other words, Japanese companies have made commitments for incremental LNG from their remotest supply option against a backdrop of falling domestic demand. In all cases, the Japanese players have opted not to buy FOB from producer projects, but instead have booked capacity at the Cove Point, Cameron, and Freeport LNG export facilities — all plants that require offtakers to secure and transport the feedgas supply for LNG production. This type of arrangement carries with it the need to set up gas trading desks in the U.S., with front-, middle- and back-office personnel, plus operations staff, representing additional fixed costs. What was the motivation for these commitments, made by no less than seven of Japan’s major LNG buyers, how successful have they been, and what lies in store for these volumes that the country does not appear to need? Today, we look at where these volumetric commitments fit, not only in the portfolios of the capacity holders but within the broader context of LNG commerce and commoditization.