RBN Energy Blogcast

The U.S. government recently released the final rules for the Section 301 fees proposed earlier this year, intended to address the dominance of China’s shipbuilding industry. According to the new rules, exports on Chinese-owned, -operated or -built vessels are mostly excluded — great news for U.S. energy producers and exporters, especially in the NGL sector. In addition, things are starting to change in the LPG markets due to the U.S./China tariff war. Propane vessels are being diverted, at least one ethane cargo has been scrapped, and China is reportedly looking into exempting ethane from its 125% import tariff. In today’s RBN blog, we look at what the latest developments mean for the U.S. energy industry. 

Rising demand for electricity to serve data centers, manufacturing and other power-consuming sectors of the economy is spurring the development of scores of gas-fired plants — up to 100 gigawatts (GW) of new capacity by 2040. How much power those new plants will actually generate — and, with that, how much natural gas they will require — remain open questions, however. A recent study indicates that the vast majority of incremental power demand over the next 15 years could be supplied by solar and wind and that gas demand for power may remain pretty much flat. But the Trump administration’s dim view of most renewables — and clear preference for fossil fuels — suggest otherwise. In today’s RBN blog, we discuss gas demand for power in the late 2020s and 2030s. 

Over the past 15 years, the U.S.’s crude oil supply/demand balance has been transformed by the Shale Revolution. Increasing production unlocked through horizontal drilling and hydraulic fracturing have pushed up the nation’s overall supply without an equal change in refining capacity, resulting in significant changes in regional balances. In today’s RBN blog, we discuss what PADD-by-PADD crude oil supply/demand balances can tell us and preview our latest Drill Down Report. 

Tech giants such as Google, Amazon and Meta have long sought to meet their data-center power needs while at least limiting their greenhouse gas (GHG) emissions. But while many developers and utilities have turned to natural gas to power data centers because of its ability to provide reliable 24/7 power, renewable generation continues to play a role, especially if it includes plans to utilize on-site battery storage. Data centers are increasingly being co-located near new renewable generation sources, which can also boost grid reliability, as we explain in today’s RBN blog. 

Taking a nine- or 10-figure energy infrastructure project from concept to fruition is never easy. Siting dilemmas, permitting woes, commitment-wary customers, financing snags, legal challenges — there are seemingly endless hurdles. And that’s in normal times. Add in market volatility and fast-changing governmental policies and a developer’s job becomes darn-near impossible. In today’s RBN blog, we discuss midstream companies’ uphill battle in advancing infrastructure projects in 2025, focusing on a recently announced greenfield natural gas storage project along the Texas Gulf Coast. 

The boundaries of what we typically think of as the Haynesville Shale in Northeast Texas and Northwest Louisiana are expanding. E&Ps are increasingly moving out from the core producing acreage and exploring new frontiers, including the far western part of the dry-gas shale play. Wrangling gas from this prospect is challenging, with deeper, high-pressure reservoirs, temperatures up to 450°F and wells drilled to extreme depths of up to 19,000 feet. But with new technology, tenacity and a little bit of luck, it could be quite promising. In today’s RBN blog, Part 1 of a miniseries, we’ll discuss what’s happening in the far western part of the Haynesville. 

The record $120 billion upstream M&A spending spree in 2024 focused on the consolidation of Permian Basin positions by the major U.S. publicly traded oil and gas companies. With crude oil prices stagnant in the $70-$80/bbl range, producers were driven to boost Tier 1 acreage and capture operational synergies to fund the generous shareholder returns demanded by their investor base. When the dust cleared at year-end, the larger E&Ps we track — plus supermajor ExxonMobil — closed or announced deals on acreage that generated about 1.5 MMboe/d of production, almost 25% of their 2023 Permian output. In today’s RBN blog, we’ll analyze what this unprecedented consolidation means for Permian production going forward. 

In an industry such as oil and gas that is beset with more uncertainty than usual of late due to geopolitical upsets, bubbling trade wars and a recent plunge in crude oil prices, being a larger company with the resources to survive the turbulent times — and thrive when the sailing is smoother — is more important than ever. For Western Canada’s energy sector, this has meant companies getting bigger through mergers. In today’s RBN blog, we discuss the planned combination of Whitecap Resources and Veren, one of the largest deals to emerge in the region in recent memory, as well as several other recent transactions that have been part of the consolidation wave. 

The West Coast energy market, PADD 5, is undergoing a profound transformation. Consumption of petroleum-based refined products is declining due to a host of factors including increased renewable diesel (RD) usage, slowing population growth, electric vehicle (EV) penetration and fuel efficiency improvements, just to name a few, but that’s only half the story. Further upping the stakes, crude oil production in the region has declined faster than downstream consumption, so it has had to increasingly rely on imported barrels to support its dwindling refinery throughput. In today’s RBN blog, we look at how the West Coast’s supply of refined products and crude oil has evolved over time and why its reliance on imports has grown. 

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. 

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. 

As the clock approached midnight on December 31, E&P managements and shareholders likely clinked champagne flutes to celebrate a remarkable four years of prosperity for an industry that had been nearly shattered by two decades of periodic financial crisis. Soaring post-pandemic commodity prices and gold-plated balance sheets provided generous cash flows, enabling substantial shareholder payouts that restored investor support, but after a period of relative stability the outlook for the E&Ps we follow is uncertain. In today’s RBN blog, we’ll review the cash-allocation strategies used by U.S. oil and gas producers in 2024 and examine the factors that could dramatically impact the sector’s performance in 2025. 

Starting on April 10, China will enact an 84% reciprocal tariff on imports of U.S. goods. This increase was in response to the 104% tariff that the U.S. placed on imports of Chinese goods, which was subsequently raised to 125% by President Trump on April 9. China is likely to retaliate further. Unlike China’s February retaliatory tariffs of 10%-15% on U.S. oil and LNG, this time NGLs and all energy products are included. These higher tariffs have the potential to destroy propane and ethane exports from the U.S. In today’s RBN blog, we look at the potential impact of China’s reciprocal tariffs on the propane and ethane markets.

The rapid growth in U.S. natural gas production and LNG exports over the past 10 years was just the beginning. Between now and 2035, gas production in the Permian, Eagle Ford, Haynesville and other plays will continue rising, the Gulf Coast’s LNG export capacity will double and many new pipelines will be built. New gas-fired power plants will be added, too. The shifts in gas flows as new production and infrastructure come online will be frequent and often sudden, as will the changes in basis at gas hubs throughout Texas and Louisiana. Is there any way to make sense of it all? There sure is. In today’s RBN blog, we continue to explore how our Arrow Model helps guide the way. 

Growing power demand for data centers has been one of the biggest stories in energy markets over the past year, with natural gas-fired power plants emerging as the primary choice for developers seeking to provide the 24/7 power these massive, energy-intensive sites require. That has led many energy firms to unveil plans to sell power directly to data centers but many tech giants have also announced their own deals. In today’s RBN blog, we’ll dive into recent announcements from firms like Apple, Amazon, Google, Meta and Microsoft, which intend to collectively spend about $300 billion this year alone to boost their AI (artificial intelligence) capabilities. 

The North American energy landscape has undergone significant shifts in production, infrastructure and pricing for crude oil, natural gas and NGLs over the past few years and developments within Canada have strengthened its role in the global energy trade, creating opportunities and reshaping supply chains. Yet, the market is constantly changing and today geopolitics and the potential impact of tariffs weigh heavily on the relationship between Canada and the U.S., North America’s two producing heavyweights. That shifting landscape is the subject of today’s RBN blog and a topic we’ll be discussing at our upcoming School of Energy Canada, set for August 26-27 in Calgary. Fair warning, this blog includes an unabashed advertorial for the conference.  

President Trump’s inauguration has pushed a flurry of policy changes, including exhortations to the E&P industry to boost U.S. oil and gas output dramatically. However, in their year-end earnings calls, the major domestic producers struck a more cautious and calmer tone, sticking to the same themes they adopted to recover financial stability and win back investors after the pandemic. Total 2025 capital spending by the 37 major U.S. E&Ps we cover is forecast to drift slightly lower from 2024 levels as they continue to eschew growth in favor of maximizing cash flows and shareholder returns. In today’s RBN blog, we review 2025 investment plans by company and peer group, highlighting trends and reviewing their impact on production, and explain why any additional increases are likely to come from producers with significant gas assets. 

After a record run of negative pricing last spring and summer, the Permian Basin collectively cheered as WhiteWater’s Matterhorn Express pipeline began flowing last October, bringing much-needed takeaway capacity to the area. Cash prices at the Waha Hub rebounded and the basin had a relatively uneventful winter, but prices began dropping in early March and have once again traded below zero for most of the past few weeks. This has taken the market somewhat by surprise, as many expected the impact of Matterhorn’s startup to last more than a few months. Prices jumped back above zero on Wednesday and above $1/MMBtu on Thursday, but with major pipeline maintenance coming next week, any relief is likely to be short lived. In today’s RBN blog, we’ll look at what’s driving the recent run of negative pricing in the Permian Basin and what it means until additional infrastructure comes online next year. 

As crude oil pipelines from the Permian to the Gulf Coast edge closer to full utilization, it’s becoming a challenge for producers and shippers alike. Amid this capacity crunch, converting Enterprise’s Midland to ECHO 2 (M2E-2) pipeline back to crude oil service can’t come quickly enough. In today’s RBN blog — the latest in our series on Permian crude oil pipelines — we discuss Enterprise’s crude oil footprint from West Texas to Houston. 

Over the next couple of years, six new pipelines and expansion projects will bring 11.8 Bcf/d of incremental natural gas supplies to the Texas/Louisiana Gulf Coast. During the same period, more than 8 Bcf/d of new LNG export capacity will move that gas to international markets. The impact of this onslaught of gas flows will be anything but orderly. Inflows will never equal outflows. Pipes will arrive early with supplies, with LNG terminals coming along later. Gas flows will shift from west to east, and north to south, in chaotic patterns that will upend historical price relationships. Is there any way to make sense of all this? There sure is, as we discuss in today’s RBN blog. All you need is the right arrow pointing the way. 

Two factors — public concern about soaring utility bills and President Trump’s strong opposition to offshore wind — are forcing New England to rethink its once-ambitious plans for a renewables-heavy electric grid and reassess how to meet its power-generation needs in the late 2020s and early 2030s. One possibility would be to expand the region’s access to piped-in natural gas, but midstreamers’ previous efforts to add pipeline capacity were beaten back time and again. In today’s RBN blog, we discuss New England’s ongoing debate about what to do next. 

Most conversations and analyses around hydrocarbon prices tend to focus on crude oil, if for no other reason than the direct exposure we experience when filling up at the pump. After the commodity price crash in early 2020, which threatened the financial stability of U.S. E&Ps, a subsequent surge in oil prices drove a remarkable recovery, winning back investor confidence in the industry. Crude realizations have subsequently declined, slowly but steadily eroding producer results. Fortunately, the outlook for natural gas, which represents just under half the total output of our 38 U.S. E&Ps, has begun to brighten. In today’s RBN blog, we analyze Q4 2024 results for the major E&Ps we cover with a focus on the impact of rising natural gas prices. 

It might seem crazy to talk about expanding crude oil and diluent pipeline systems between Canada and the U.S. amid what could escalate into an all-out trade war between the two nations. However, Enbridge, one of the largest pipeline operators in the world, is doing just that — actively planning and investing in pipeline expansions for its Mainline, Express-Platte and Southern Lights systems that would help move an ever-rising tide of Canada’s oil sands crude to market in the years ahead. We examine Enbridge’s plans in today’s RBN blog. 

Huge fees may be coming to ships built in China each time they arrive at a U.S. port. During a hearing in Washington on Monday, the Office of the U.S. Trade Representative (USTR) heard comments on its January 2025 study that laid out China’s strategy to achieve dominance in the global maritime, logistics, and shipbuilding sectors — a strategy that has worked spectacularly. Since 1999, China’s share of the global shipbuilding market has soared from 5% to 50%. The USTR argues that China’s growing control over the maritime sector poses serious economic and national security risks to the U.S., making immediate action necessary. Proposed measures include imposing port fees from $1 million to $1.5 million per port entry. If implemented, the fees would substantially increase costs for exports and imports using Chinese ships. That could have incredibly disruptive impacts on most oceangoing transport, and energy products are no exception — unless they get an exception! In today’s RBN blog, we explore the background of the USTR’s China port-fee proposal and what it could mean for global energy logistics. 

More than 9 billion gallons of propane were delivered to U.S. consumer markets in 2024, primarily for residential heating and cooking. Demand is highly seasonal, which brings a unique set of challenges for buyers, especially on the wholesale side of the market, but production tends to be steadier over the course of the year. In today’s RBN blog, we show how wholesalers balance supply and demand and the critical role of the winter-to-summer ratio. 

A half dozen large midstream companies provide the full gamut of “wellhead-to-water” services for Permian-sourced natural gas and/or NGLs, and a couple of those offer the same for crude oil as well. For Enbridge and Plains All American, the clear focus has been on crude — pipelines, storage and marine terminals — though Enbridge has been rapidly expanding its portfolio of Permian-to-Gulf gas assets too. In today’s RBN blog, we look at what Enbridge and Plains have and what they are planning. 

Mexico’s LNG sector has seen notable advancements in the past year, including new export project announcements and strategic investments. But many of the proposed LNG projects require extensive pipeline buildouts — no easy task south of the border and perhaps the biggest impediment most of the export projects face. In today’s RBN blog, we’ll look at where things stand with Mexico’s LNG sector and the export projects under development. 

Western Canada’s natural gas market never really seems to catch a break. Prices this winter have remained well below those across much of the rest of North America thanks to an all-too-common combination of insufficient pipeline export capacity from the region, bloated gas storage and robust supply growth. Even with forward price prospects for much of the rest of the continent looking buoyant, with more gas expected to head to expanding Gulf Coast LNG terminals and a storage-refill season that will be stronger than last year, price upside for Western Canada looks to be minimal at best and will be partly dependent on the rate of gas intake to LNG Canada, as we explain in today’s RBN blog. 

The Trump administration announced on February 26 that it is ending Chevron’s permit to operate in oil-rich Venezuela, which will halt U.S. imports of Venezuelan crude by early April. These changes, combined with other recent developments, are likely to significantly impact complex U.S. Gulf Coast refiners relying on heavy crude. In today’s RBN blog, we’ll discuss these impacts — an issue our Refined Fuels Analytics (RFA) practice examined in its recently updated Future of Fuels report. 

Crude-oil-focused drilling and completion in the Permian Basin is generating fast-increasing volumes of associated gas — and creating opportunities for midstream companies that provide “wellhead-to-water” services for natural gas and NGLs. ONEOK has become a much bigger player in this space via several transformational acquisitions and MPLX has been making moves of its own. (The companies also are working together on a new LPG export terminal — and more.) In today’s RBN blog, we continue our review of Permian-to-Gulf midstreamers’ expansion plans with a look at what ONEOK and MPLX are up to. 

The Rocky Mountain region (PADD 4), with a population that is both smaller and more spread out than other parts of the Lower 48, consumes only around 650 Mb/d of refined products — just one-fourth the volume of the next-smallest PADD. That limits the need for refinery capacity, which matches the region’s average annual consumption and is only outstripped in the summer months. Yet, the Shale Revolution has impacted the Rockies as much as any other region, boosting production in the Denver-Julesburg (DJ) and Uinta basins, and the Montana portion of the Bakken. At the same time, the area has also seen increasing volumes coming in from PADD 2 and Canada. In today’s RBN blog, we’ll look at how PADD 4 dispenses these barrels and its role in balancing continental crude oil supply and demand. 

President Trump’s flurry of executive orders upon returning to office included one titled “Unleashing Alaska’s Extraordinary Resource Potential,” which aims to see the realization of the long-dormant Alaska LNG project, a multibillion-dollar plan to bring natural gas several hundred miles from Alaska’s North Slope to Anchorage and Cook Inlet for eventual liquefaction and export. The president’s endorsement renewed interest in a project that has been on the drawing board for more than 30 years. In today’s RBN blog, we look at why there is renewed interest in the project, some of the hefty challenges it would need to overcome, and why many still see it as a long shot. 

As the global crude oil market continuously evolves, so do the tools that traders, refiners and producers rely on to navigate its complexities. Among these tools, futures contracts play a pivotal role, allowing market participants to manage risk and ensure liquidity. In today’s RBN blog, we’ll explore what sets apart two major futures contracts for West Texas Intermediate (WTI) crude oil, focusing on the differences in location, connectivity and quality — and how those distinctions define their roles in the market. 

New England is determined to shift toward a greener electric grid, but the region’s plan to slash its current reliance on natural gas (and backup fuel oil — and sometimes coal) by ramping up offshore wind and solar (and backup batteries) has hit a seemingly immovable object. President Trump, a staunch opponent of offshore wind, on Day 1 of his second administration ordered a halt to new leases and permits and directed his Interior Secretary to review existing permits. As we’ll discuss in today’s RBN blog, those moves have left New England power planners scratching their heads, and may even resurrect the possibility of expanding natural gas pipeline capacity into the region. 

The pace of announcements for planned data centers accelerated in 2024 and has continued to gather steam in 2025, with natural gas-fired power plants emerging as a frequent choice, along with nuclear power, to provide the around-the-clock electricity that large-scale data centers want and need. In today’s RBN blog, the first in a series, we’ll detail plans by several well-known energy firms to construct new gas-fired plants that would produce electricity specifically for data centers. 

The handful of midstream companies that provide a full range of “wellhead-to-water” services between the Permian and the Gulf Coast are in growth mode, advancing a long list of gas processing plants, takeaway pipelines, fractionators and export terminal expansions. Last time we looked at what Enterprise Products Partners and Energy Transfer are up to. In today’s RBN blog, we shift our spotlight to what Targa Resources and Phillips 66 are planning, with Targa building a slew of projects and P66 growing primarily through organic opportunities that have arisen following recent bolt-on M&A. 

The U.S. power sector is undergoing a major expansion to keep pace with the rising demand for electricity from data centers and other consumers, and trying to do a lot at once. Keep a lid on greenhouse gas (GHG) emissions by adding wind, solar and other renewables. Maintain grid reliability by supplementing variable renewable energy with more around-the-clock sources like natural gas-fired power plants. Oh, and keep power costs down, too. That’s a big collective ask, and to help make it possible, power grids are turning to so-called “virtual power plants” (aka VPPs) that, with an assist from computers and software, aggregate smaller power sources, batteries and flexible demand to provide power to the grid much like a traditional combined-cycle plant would. In today’s RBN blog, we’ll introduce VPPs and explain why they’re worth learning about. 

The U.S. crude oil market has undergone a drastic shift since the Shale Revolution. After a quarter-century of declining production and increasing dependence on imported oil, the U.S. has become the world’s leading producer. This transformation turned the U.S. into a major exporter and a critical supplier to the international market and also led to an evolution in crude oil trading. In today’s RBN blog, the first in a series, we’ll explore the history of West Texas Intermediate (WTI) futures contracts. 

The long-term contract has been the cornerstone of the global LNG industry since its inception. Such contracts between upstream LNG producers and downstream utility companies have provided buyers with security of supply over a protracted period while guaranteeing producers sufficient income to justify the investment in export facilities and shipping fleets. But times are changing, with significant LNG volumes under long-term contracts scheduled to expire by 2031. In today’s RBN blog, we look at the potential implications for LNG buyers and producers around the world, the options available to them, and how their choices may impact LNG commercial models. 

More than 9 billion gallons of propane were delivered to U.S. consumer markets in 2024, primarily for residential heating and cooking. The final step in propane’s pathway to the retail market is managed by a large group of companies known as retailers, which range in size from “mom and pop” operations that run only a couple of cars serving a local market to companies with fleets of cars and multiple supply points. As we detail in today’s RBN blog, the propane business requires a huge focus on logistics and personal relationships. 

Strategic Petroleum Reserve (SPR) inventories have been climbing for more than a year, but they could go much higher if President Trump has his way, as one of his major campaign promises was to refill the SPR “to the very top,” a goal he has repeated since his return to the Oval Office. Current inventories sit just below 400 MMbbl, leaving the SPR about 320 MMbbl shy of maximum capacity. But the refilling process may not be as straightforward as one might think, as three of the four SPR storage sites have experienced construction upgrades in the last year — which means things could go slower than anticipated. In today’s RBN blog, we’ll discuss the challenges of filling up the SPR and detail four scenarios for how the process might play out. 

Edgewater Midstream, a relatively new player in the refined products storage and delivery space, acquired a pair of potentially valuable assets from Shell in the Deer Park, TX, area in December. It now owns the Colex terminal, the starting point of the all-important Colonial Pipeline system, and the Sinco products pipe network, which could offer another pathway to Desert Southwest markets served by a dwindling number of California refineries. In today’s RBN blog, we will examine Edgewater’s new assets and the market opportunities they may open up. 

In their first earnings calls of 2025, the handful of large midstream companies that provide the gamut of “wellhead-to-water” services in Texas laid out plans for yet another round of projects — everything from gas processing plants and takeaway pipelines to fractionators and export terminal expansions. At the same time, many of these same midstreamers expressed a degree of caution about overbuilding. They sought to reassure Wall Street that they were only approving plans underpinned by strong commercial support. In today’s RBN blog, we discuss the latest capital spending plans of this select, upper tier of midstream service providers. 

A significant shift is underway within Mexico’s energy landscape, reflected by the development of large-scale oil and gas infrastructure projects in the country, particularly the Southeast Gateway and Sierra Madre gas pipelines that would move U.S.-sourced natural gas across Mexico. These projects — the first an undersea pipe in the Gulf of Mexico and the second a pipe across the country’s northern tier — would enhance Mexico’s gas transport capacity while supporting power generation and industrial development. Mexico, which is already heavily reliant on imports of U.S. gas, is forecast to see gas demand rise in the coming years as domestic production drops. In today’s RBN blog, we look at those two pipelines, their challenges, and how the potential for U.S. tariffs on Mexican imports might complicate the future of both projects. 

PADD 3 has it all — crude oil production from the prolific Permian Basin, a string of refineries along the Gulf Coast, and a fair bit of refined product consumption. Its importance in crude oil production and refining has allowed it to play a central role in the nation’s crude oil supply-and-demand balance. This is especially true regarding crude oil exports, as it’s responsible for virtually all of the U.S. total that can top 4 MMb/d. Because of this, PADD 3 has a significant and growing influence in balancing domestic and international markets for crude oil and refined products. In today’s RBN blog, we’ll look at how the Shale Revolution has transformed the Gulf Coast and how its connectedness with international markets has reaffirmed its dominant position. 

Globally, government policies have shifted away from petroleum in recent years toward lower-carbon alternatives such as renewable fuels and electric vehicles (EVs), largely driven by worries about climate change. This has pushed down investment in petroleum refining, and RBN’s Refined Fuels Analytics (RFA) practice predicts global net refining capacity will increase by only 2.1 MMb/d, or 422 Mb/d annually, from 2025-29 — the slowest rate in 30 years. In today’s RBN blog, we’ll discuss the upcoming refinery closures, proposed projects, and the obstacles new and existing refiners face. 

The decision by the U.S.’s largest independent propane wholesaler to exit the business serves as a reminder of the challenges and risks that companies like it face. The move also highlights the fact that at least some other independent wholesalers — including the presumed buyer of NGL Energy Partners’ propane-related assets — believe that by increasing their scale and scope they can compete more effectively with their two classes of competitors: affiliates of big midstream companies and affiliates of propane retailers. In today’s RBN blog, we discuss what the latest M&A activity in the propane space reveals. 

We defy you to name an oil and gas producer that’s been on the buying side of more $1-billion-plus M&A than Permian pure play Diamondback Energy, which announced February 18 that it had agreed to purchase a chunk of Midland Basin assets from Double Eagle IV, one of the Permian’s largest privately held producers, for just under $4.1 billion. You’d be equally hard-pressed to find a team that’s assembled and flipped more Permian acreage and production than the folks at Double Eagle. In today’s RBN blog, we discuss the newly announced Diamondback/Double Eagle IV deal and what it gives Diamondback, the fourth-largest producer in the Permian after ExxonMobil, Chevron and Occidental Petroleum. 

In the race to build the next deepwater crude oil export terminal in the Gulf of Mexico, Sentinel Midstream’s proposed Texas GulfLink (TGL) has become one of the frontrunners. TGL’s plan gained its crucial Record of Decision (ROD) Approval from the U.S. Department of Transportation’s Maritime Administration (MARAD) on February 14, but there is still some distance to go before a final investment decision (FID) is reached. In today’s RBN blog we’ll discuss Sentinel’s TGL plan, why it might be uniquely positioned to move forward, and the other contenders still in play. 

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.