

When it comes to midstream development in the Northeast, Appalachian natural gas producers have learned by now not to hold their breath. The region is notorious for its staunch environmental opposition to hydrocarbon infrastructure and its propensity for sending gas pipeline projects to the trash pile. Against all odds, however, midstream development in the region has thawed in recent months, in large part spurred by the unlikely advancement of Mountain Valley Pipeline (MVP), the long-embattled project to move up to 2 Bcf/d from the Appalachia gas supply basin to the Transco Corridor, which runs north-south along the Eastern Seaboard. In today’s RBN blog, we take a look at historical flows on Williams’s Transco Pipeline and what they can tell us about how MVP and Transco’s own planned expansions might reshape gas flows along the corridor.
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.
WTI was down again by another 1.4% on Monday following a 2.5% drop on Friday as the market remains unimpressed by OPEC+ production cuts announced last Thursday. WTI settled at $73.04/bbl, off $1.03/bbl. OPEC+ announced its intentions to reduce production by approximately 2.2 MMb/d for Q1 2024,
It is winter in propane country, and even though it has been a relatively mild one so far, propane prices have been remarkably weak. For one thing, the ratio of Mont Belvieu propane to WTI crude oil has been in the dumper all year, averaging a paltry 35% since March. Last year for the same peri
Report | Title | Published |
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TradeView Daily Data | TradeView Daily Data - December 4, 2023 | 12 hours 54 min ago |
NATGAS Billboard | NATGAS Billboard - December 4, 2023 | 20 hours 5 min ago |
NATGAS Permian | NATGAS Permian - December 4, 2023 | 21 hours 52 min ago |
Chart Toppers | Chart Toppers - December 4, 2023 | 23 hours 5 min ago |
TradeView Report | TradeView Crude Oil Price Analytics & Differentials - December 1, 2023 | 1 day 8 hours ago |
When it comes to midstream development in the Northeast, Appalachian natural gas producers have learned by now not to hold their breath. The region is notorious for its staunch environmental opposition to hydrocarbon infrastructure and its propensity for sending gas pipeline projects to the trash pile. Against all odds, however, midstream development in the region has thawed in recent months, in large part spurred by the unlikely advancement of Mountain Valley Pipeline (MVP), the long-embattled project to move up to 2 Bcf/d from the Appalachia gas supply basin to the Transco Corridor, which runs north-south along the Eastern Seaboard. In today’s RBN blog, we take a look at historical flows on Williams’s Transco Pipeline and what they can tell us about how MVP and Transco’s own planned expansions might reshape gas flows along the corridor.
The drive to minimize methane emissions along the natural gas value chain — and have entities like MiQ and Project Canary certify or differentiate natgas as “low-emissions” — may have started upstream with E&Ps eager to boost their environmental cred, but the effort also has been monitored closely by gas utilities, industrials and others that consume large volumes of gas, and regulators. In what may be a hint of what’s to come, a number of initial deals for certified/differentiated gas have been announced and a handful of pilot programs are in the works. In today’s RBN blog, we continue our examination of the emerging low-emissions natgas market with a look at “first-mover” gas buyers and regulatory bodies.
There’s a lot of nitrogen out there — it’s the seventh-most common element in the universe and the Earth’s atmosphere is 78% nitrogen (and only 21% oxygen). And there’s certainly nothing new about nitrogen in the production, processing and delivery of natural gas. That’s because all natural gas contains at least a little nitrogen. But lately, the nitrogen content in some U.S. natural gas has become a real headache, and it’s getting worse. There are two things going on. First, a few counties in the Permian’s Midland Basin produce gas with unusually high nitrogen content, and those same counties have been the Midland’s fastest-growing production area the past few years. Second, there’s the LNG angle. LNG is by far the fastest-growing demand sector for U.S. gas. LNG terminals here in the U.S. and buyers of U.S. LNG don’t like nitrogen one little bit. As an inert gas (meaning it does not burn), nitrogen lowers the heating value of the LNG and takes up room (lowers the effective capacity) in the terminal’s liquefaction train. Bottom line, nitrogen generally mucks up the process of liquefying, transporting and consuming LNG, which means that nitrogen is a considerably more problematic issue for LNG terminals than for most domestic gas consumers. So as the LNG sector increases as a fraction of total U.S. demand, the nitrogen issue really comes to the fore. In today’s RBN blog, we’ll explore why high nitrogen content in gas is happening now, why it matters and how bad it could get.
Appalachian natural gas producers got good news earlier this month: Williams announced it was moving forward with the Southeast Supply Enhancement project, a large-scale expansion of southbound capacity out of the Northeast on its Transco Pipeline system. Not only that, but it super-sized the project to 1.4 Bcf/d of capacity — nearly double the 800 MMcf/d it had offered in an open season held this summer. The project is one of several brownfield expansions planned to provide additional supply access in Transco’s premium Zone 5 market area, which runs through Virginia and North Carolina — and the first large-scale takeaway expansion to be announced in the area since the long-delayed Mountain Valley Pipeline (MVP) was cleared for completion following years of regulatory and legal hurdles. In today’s RBN blog, we provide the latest on the Transco Corridor expansions.
Over the past couple of years, a growing number of natural gas producers — from global integrateds like ExxonMobil, Chevron and BP to E&Ps large, medium and small — have contracted with entities like MiQ and Project Canary to scrutinize their upstream operations and score their relative success in minimizing methane emissions. By some estimates, as much as one-third of U.S. gas production is already “certified” or “differentiated,” and with growing interest in “low-emissions” gas among domestic and international buyers the trend seems likely to accelerate. In today’s RBN blog, we continue our look at certified/differentiated gas with a review of the gas producers leading the way.
Six months ago, the U.S. West Coast natural gas market looked like it was in dire straits. A harsh winter had depleted stocks to the lowest level in over a decade and it seemed like the region would be hard-pressed to refill storage to a reasonable level, given limited and constrained pipeline options to flow incremental gas west. Instead, a combination of mild weather and operational changes eased demand and pipeline constraints, and Pacific Region storage staged a remarkable comeback this summer. In today’s RBN blog, we delve into how the region escaped a worst-case scenario heading into the heating season.
LNG export projects looking to take a positive final investment decision (FID) need to sell a high proportion of their nameplate capacity under long-term contracts to ensure sufficient cash flows to underpin the project and obtain financing. U.S.-based projects (new and expansions) totaling more than 350 million tons per annum (MMtpa, 48.3 Bcf/) — against a current global market of 400 MMtpa (52.9 Bcf/d) — are vying for creditworthy offtakers from multiple markets in their pre-FID deliberations. The sense of urgency among project sponsors has been boosted by the Russia/Ukraine war and a potentially resurgent Chinese economy, both of which should promise a bright future for new projects. Plenty of those have reached FID in the last couple of years, but what is holding others back from taking the same step? In today’s RBN blog, we’ll look at some of the factors impacting those decisions and the long-term implications that flow from them.
Certified or differentiated natural gas — an upgrade from the old “responsibly sourced gas” — is on the rise. More and more producers, pipeline companies, gas utilities and LNG exporters and buyers want their gas to be certified as having a lower emissions profile, and for a variety of reasons, chief among them achieving their ESG goals and winning over ESG-minded investors and customers. But while there’s a consensus that methane and other greenhouse gas (GHG) emissions can and should be reduced significantly, there are differing views about the best ways to monitor wells, pipelines and other infrastructure for methane leaks, measure total emissions, and ensure that emission reductions are real and sustainable. In today’s RBN blog, we continue our deep dive on certified/differentiated gas with a look at the approaches the leading certification/differentiation entities and others are taking in emission monitoring, measuring and scoring.
Continued growth in Permian crude oil production can’t happen without sufficient infrastructure — not just takeaway capacity for crude, natural gas and NGLs but also the capacity to process the fast-increasing volumes of associated gas being produced in the Midland and Delaware basins. The incremental need for processing capacity is enormous, as evidenced by the ongoing, almost frenetic build-out of gas processing plants across the Permian. More than 1 Bcf/d of new capacity is slated to come online by the end of this year, with another 1.9 Bcf/d in the first half of 2024 and another 1.8 Bcf/d after that. In today’s RBN blog, we discuss the race to add processing plants in key locations in West Texas and southeastern New Mexico and the drivers behind it.
Storage has long been a critically important balancing mechanism in the Lower 48 natural gas market. Now, after languishing for much of the Shale Era, storage values are coming out of the doldrums. The key driver behind this change is that, unlike in the old days, when the storage market was driven primarily by the intrinsic value of capacity — i.e., the need to sock away gas in the lower-demand summer months for use in the peak winter months — the value of storage is being driven almost exclusively by extrinsic economics — i.e., how flexible and responsive capacity allows market participants to manage supply and demand during short-term market swings. This flexibility and responsiveness have become increasingly important criteria for ensuring reliability as LNG export facilities and an increasingly renewables-heavy power sector navigate frequent demand fluctuations day to day, or even intraday, as well as during high-stakes, extreme weather events like 2021’s Winter Storm Uri. In today’s RBN blog, we delve into the fundamental shifts influencing today’s storage market.
New England is hell-bent on decarbonizing quickly, and it’s been making some progress. But like it or not, the region still depends heavily on natural gas for both power generation and space heating, and gas supplies are stretched to the limit during periods of extreme winter demand. Worse yet, the Everett LNG import terminal, which for years has fed a big, soon-to-close gas-fired power station and supported the Boston area’s gas grid, may be on the verge of shutting down. Well, help may finally be on the way. Enbridge recently proposed an expansion to its 3-Bcf/d Algonquin Gas Transmission pipeline system. The question is, can it get built in a region notorious for its opposition to energy infrastructure projects? In today’s RBN blog, we discuss Enbridge’s Project Maple and the role it could play in New England’s aggressive plan to reduce its greenhouse gas (GHG) emissions.
Appalachian natural gas producers and marketers are adapting to a new status quo — a world where new pipeline takeaway capacity out of the Northeast is hard to come by and is more or less capped ad infinitum. Without the assurance of pipeline expansions, regional gas producers are no longer drilling with abandon in hopes that the capacity will eventually get built. Instead, producers are practicing restraint by slowing drilling activity, delaying completions and choking back producing wells to manage their inventory during periods of lower demand and prices. In today’s RBN blog, we consider what this new playbook will mean for pricing trends in the supply basin.
LNG feedgas demand has averaged a record of about 12 Bcf/d this summer and fall. While that may sound like an impressive number (and it is), it could increase significantly — even without new capacity additions — over the next few months as seasonal demand rises and maintenance activity slows. And that’s just for starters. Next year, the first of several planned LNG export terminals and expansions of existing ones will start commissioning, and by the end of this decade feedgas demand may well double. In today’s RBN blog, we look at how current LNG feedgas demand stacks up compared to past years, the factors driving current demand, and the potential for additional upside.
Government forecasts are predicting a sharp drop in natural gas demand in the power sector in the coming decades based on an expectation that the renewable capacity build-out will accelerate and displace other sources. However, forecasts in the past decade have consistently and severely underestimated gas burn for power. In today’s RBN blog, we consider the pitfalls of forecasting gas consumption in a world often focused on pushing a renewables-heavy generation stack.
U.S. natural gas producers had a rough start to 2023, with spot prices dipping to just above $2.15/MMBtu this past spring. But optimism was abundant in midyear earnings calls on expectations that demand will eventually soar, driven largely by a near-doubling of U.S. LNG export capacity by the end of the decade. A key question, however, is whether E&Ps have built the inventories of proved reserves to support future production increases to meet that demand. In today’s RBN blog, we analyze the crucial issue of reserve replacement by the major U.S. Gas-Weighted E&Ps.