RBN Energy

The transition of U.S. E&Ps to capital discipline has led to historic shareholder returns and won back legions of investors who had virtually abandoned the industry until a few years ago. But while it might be tempting to conclude producers must finally have their financial houses in good order, a lot of us have witnessed a few boom-and-bust cycles in our time and remain hypervigilant for any signs of financial instability, especially considering that commodity prices could weaken at any time. In today’s RBN blog, we analyze the impact of lower price realizations and capital allocation decisions on the balance sheets of the major U.S. independent oil and gas producers. 

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 Jeremy Meier - Friday, 5/17/2024 (3:15 pm)

US oil and gas rig count was up slightly to 604 for the week ending May 16, up one vs. a week ago according to Baker Hughes. Rigs were added in the Anadarko (+2), Haynesville (+1) and Gulf of Mexico (+1), while the Permian (-2) and Eagle Ford (-1) both lost rigs.

By Kristen Hays - Friday, 5/17/2024 (11:45 am)

Navigator Holdings is planning a clean ammonia export project along the U.S. Gulf Coast. Executives said this week that Navigator has committed $2.5 million in initial funding with more to come when the company moves toward a final investment decision (FID) and construction.

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Daily Energy Blog

With all the talk about U.S. LNG exports and plans for more LNG export capacity, it can be easy to forget that more than 6 Bcf/d of U.S. natural gas — mostly from the Permian and the Eagle Ford — is being piped to Mexico. That’s more than 3X the volumes that were being piped south of the border 10 years ago, a tripling made possible by the buildout of new pipelines from the Agua Dulce and Waha hubs to the Rio Grande and, from there, new pipes within Mexico. And where is all that gas headed? Mostly to new gas-fired power plants and industrial facilities — a handful of new LNG export terminals being planned on that side of the border will only add to the demand. In today’s RBN blog, we discuss the ever-increasing flows of gas to Mexico and the tens of billions of dollars of new infrastructure making it all possible. 

U.S. natural gas production continues to increase, with more growth expected at least through the middle of this decade to feed new LNG export capacity coming online along the Gulf Coast. Production growth will require new infrastructure, but long-distance transmission lines have become increasingly difficult to build due to entrenched environmental opposition. Meanwhile, gathering pipes have grown in size and length, blurring the lines between gathering and transmission. In today’s RBN blog, we’ll discuss what separates gathering systems from transmission pipelines, why those differences matter, and how those systems are continuing to evolve. 

We’ve been saying for a while now that the natural gas storage market may be on the verge of a comeback. At the same time, we’ve cautioned that the world has changed since the heyday of gas storage in the mid-to-late 2000s, and that while market participants are clamoring for storage solutions and storage values are rising, what’s driving storage values today is vastly different than what drove the last big capacity build-out (which resulted in a major storage overbuild). As a result, only a handful of storage projects meeting special needs in particular places are likely to reach a final investment decision (FID). In today’s RBN blog, we discuss one such project: a greenfield storage facility under construction at two depleted dry-gas reservoirs 90 miles southeast of Dallas.

Kinder Morgan owns and operates natural gas pipelines across pretty much every part of the U.S., from California to Massachusetts and North Dakota to Florida. But if you look at a map of its gas pipeline assets, you’ll notice a focus on lines in the Lone Star State that serve as critical pathways for Permian- and Eagle Ford-sourced gas flowing to Mexico, Texas’s Gulf Coast and a number of existing and planned LNG export terminals. Now, Kinder is poised to significantly expand its pipeline network in that part of the world with the planned $1.8 billion acquisition of NextEra Energy Partners’ STX Midstream unit, as we discuss in today’s RBN blog. 

The Biden administration’s recent announcement at the COP28 climate change conference in Dubai that it has issued a final rule on reducing methane emissions from the oil and gas industry raises an important question: If the feds will be requiring every producer to phase out flaring, install new equipment, and meet new, aggressive standards for emissions monitoring and leak detection and repair, will there still be a need for entities like MiQ and Project Canary to score or assess the lower-emissions natural gas produced by a significant subset of enviro-conscious E&Ps? In today’s RBN blog, we discuss the potential impacts of the new EPA rule on gas certification/differentiation and the development of a market for low-methane gas. 

The Everett LNG import terminal, a mainstay of Boston’s gas grid, is expected to close by the end of May 2024, raising questions about future gas supply in New England. The terminal’s closure is closely tied to the imminent loss of its biggest customer, the 1,413-MW Mystic generating station — the region’s largest fossil-fuel plant. Constellation Energy, which owns both the Everett terminal and the Mystic power plant, has said it can’t keep Everett open next year when the Mystic plant closes unless another gas purchaser takes its place. In today’s RBN blog, we’ll address the impacts of Everett’s potential demise on New England in the short term and on regional gas supply during future polar vortex events.

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.