RBN Energy Blogcast

After dodging the huge tariffs on exports of U.S. LPG and ethane to China — at least until August 12 — a new wrinkle has emerged. Enterprise Products Partners said in a filing May 29 that the U.S. Bureau of Industry and Security (BIS) has flagged its exports of butane and ethane to China as a security risk; specifically, that they pose an “unacceptable risk of use in or diversion to a military end use.” Details about the licenses and how they will apply are limited at this point, but it appears they will be required for these exports to continue. In today’s RBN blog, we examine the potential impact on the ethane and butane markets. 

We’ve discussed the qualities of the Uinta Basin’s unusual waxy crude, the challenges inherent in moving it to market, and the use of machine-learning AI to optimize its extraction from two key geologic layers or “benches” deep below the rugged hills of northeastern Utah. Now, in today’s RBN blog, it’s finally time to reveal what all this tells us regarding the prospects for continued Uinta production growth; the need for new takeaway capacity, blending and refining infrastructure to handle it; and — very important — the estimated duration of economically recoverable waxy crude under various price scenarios. 

This may be the best time ever to be a manufacturer of natural gas turbines. The U.S. seems poised for a sharp increase in power demand in the coming years and order books are filling up, but it’s not all smooth sailing and significant headwinds remain. In today’s RBN blog, we will explore how rising costs, supply-chain constraints, long lead times and tariffs could impact turbine manufacturing and complicate efforts to expand gas-fired power generation. 

With more than 9 billion gallons of propane delivered to U.S. customers each year, moving those volumes to their final destination is a complex task involving pipelines, rail cars, storage (be it underground or above ground) and, ultimately, trucks. Several major factors help determine the quantity and price of propane delivered to end-use customers, including the seasonality of demand versus the steady nature of production. In today’s RBN blog, we discuss highlights from our new Drill Down Report on propane. 

Over the past month, E&P executives have addressed shareholder and analyst concerns amid the murkiest market conditions since the onset of the pandemic in Q1 2020. One industry leader pointed out that on an inflation-adjusted basis, there have only been two quarters since 2004 when front-month oil prices have been as low as they are today (excluding 2020). In today’s RBN blog, we review what we heard from E&P brass — a measured response that melded confidence in the industry’s new fiscally conservative, shareholder-focused business model; modest spending reductions; and preparations for more substantial responses to future erosion in commodity pricing. 

It has been 12 months since the Trans Mountain Expansion Project — aka TMX — finally began operations after years of delay, creating a much-needed, larger conduit to move Western Canada’s rising crude oil production to the Pacific Northwest and overseas markets. Although the customer base for exports remains limited, the Trans Mountain pipeline system has been responsible for opening up entirely new markets for Canadian crude. As we discuss in today’s RBN blog, despite its numerous delays and immense cost, the pipeline has recently seen record crude shipments and is nearing its nameplate capacity, driven by rising exports. 

It’s been about a year and a half since Next Wave Energy Partners opened its Project Traveler facility, a milestone in the energy industry. Overall, Project Traveler has exceeded production expectations and proven the innovative approach of combining ethylene and isobutane to produce high-quality alkylate. In today’s RBN blog, we’ll look at what’s been accomplished so far and dive into what’s ahead for Next Wave. 

The pipelines carrying crude oil from the Permian Basin in West Texas to the Corpus Christi area have been as jammed as an urban highway on the Friday before Memorial Day weekend. The Gray Oak Pipeline, the largest from the Permian to Corpus, has just completed the 80-Mb/d first phase of a planned two-phase expansion that will add a total of 120 Mb/d of capacity. In today’s RBN blog, we’ll discuss what this project means for pipeline congestion and crude exports out of Corpus and nearby Ingleside. 

The Marcellus/Utica region is by far the most prolific natural gas production area in the U.S., accounting for about one-third of the nation’s daily output. The shale play experienced phenomenal growth in the 2010s, its gas production rising from less than 2 Bcf/d to more than 33 Bcf/d over that decade. But the pace of growth has slowed dramatically in recent years, mostly due to takeaway constraints. In today’s RBN blog, we discuss how a combination of new pipeline projects, in-basin data center development and incremental Gulf Coast LNG demand might breathe new life into the Marcellus/Utica. 

There is tremendous buzz around natural-gas-fired turbines right now with backlogs reportedly stretching five years into the future due to supply-chain bottlenecks, labor shortages and a surge in demand. The power generation industry is poised for a major upswing as data center development and overall electricity demand continue to accelerate, driving an even greater need for gas turbines. In today’s RBN blog, we will explore why gas turbines are so challenging to build and why there’s such a manufacturing backlog. 

There’s a lot to like about the Uinta Basin’s waxy crude, but ramping up its production and use in refinery feedstock slates will require multimillion-dollar investments in rail terminals, special rail cars, heated storage, refinery equipment and other midstream and downstream infrastructure. A natural concern for E&Ps, midstreamers, and refiners is whether the basin has sufficient long-term staying power to justify the upfront costs and commitments. As we discuss in today’s RBN blog, a machine-learning-based analysis can provide many of the answers by assessing the basin’s long-term outlook under various scenarios. 

Familiar corporate names like Cummins, Freightliner and Waste Management have joined forces with dozens of less-familiar public companies and startups to form what some might call a new U.S. industry. Thousands of commercial trucks powered by compressed natural gas (CNG) are on the roads nationwide, many of them filling up at dedicated fueling stations offering a compressed form of renewable natural gas (RNG), a cellulosic biofuel typically sourced from landfills and dairy farms. In today’s RBN blog, the third and final in our series on the D3 Renewable Identification Number (RIN), we show how this young industry could emerge as a commercial success for cellulosic biofuels, although political and regulatory risk remains. 

Hydrogen has a well-established, if limited, role in the modern economy. It has been used in refining and ammonia production for decades, but its potential has long been touted in various areas, including decarbonizing hard-to-abate industrial processes such as steelmaking, as well as in larger roles in heavy-duty transportation and energy storage. The last few years have seen a significant push to expand hydrogen’s role — an attempt to capitalize on its versatility and lack of carbon dioxide (CO2) emissions —  but a number of formidable obstacles to wider adoption remain, including price, availability and infrastructure, in addition to its tenuous political support. In today’s RBN blog, we look at the challenges that make forecasting the industry’s growth difficult and the emerging consensus around the most practical end uses for hydrogen. 

The Permian’s Midland and Delaware basins have seen their share of midstream success stories the past few years — many of them privately backed efforts to gain a foothold and then expand into the big time. Navitas Midstream Partners (later sold to Enterprise Products Partners) comes to mind; so do Oryx Midstream and Brazos Midstream. Now comes Vaquero Midstream — vaquero, of course, being Spanish for cowboy — the scrappy developer of a gas gathering and processing network in the Delaware. As we discuss in today’s RBN blog, Vaquero recently announced plans to build a new high-pressure pipeline that will double the capacity of its gathering system and a new processing plant that will give it a total of 600 MMcf/d of processing capacity with a slew of interconnections to key gas and NGL takeaway pipelines. 

Serious concerns about higher costs and lower demand have left the E&P sector in a delicate position since the implementation of new U.S. tariffs, as evidenced by the Dallas Federal Reserve Bank’s recent survey of producers, who appear especially vulnerable after massive acquisition spending in 2024 to deepen and high-grade their portfolios. In today’s RBN blog, we’ll explore the impact of the 2024 acquisitions and commodity pricing on E&P debt and discuss the expected response to protect balance sheets. 

Much like a cowboy venturing into uncharted territory, E&Ps are roaming Northeast Texas and the far-western sections of the Haynesville Shale in search of more natural gas. It’s a challenging adventure, and while there’s a lot of hope and hype, the recent history of developments outside the Haynesville’s main producing areas shows that success is far from guaranteed. In today’s RBN blog, the second in a series on the Western Haynesville, we’ll discuss how some companies are handling the high-pressure, high-risk environment. 

The Trump administration’s approach to economic policy — including tariff threats to longtime allies backed by sometimes shifting policy goals — might be a sound tactical move in the long run by keeping negotiators on edge and extracting better deals. But that approach has also heightened the sense of uncertainty about where things are headed, affecting investment and long-term planning. In today’s RBN blog, we discuss how economic policy uncertainty has increased in the past few months and how it’s impacting activity in the energy sector. 

Several large, publicly held midstream companies play critical roles in transporting crude oil, natural gas and NGLs from the Permian Basin to markets along the Gulf Coast, and all of them are investing hundreds of millions or even billions of dollars to expand their Permian-to-Gulf infrastructure. But there’s a privately held outlier among them — WhiteWater Midstream, which has developed key gas pipelines in Texas and has been partnering with MPLX, Enbridge and others to own and develop a few more. In today’s RBN blog, we look at the growing portfolio of WhiteWater and the WPC joint venture (JV) and discuss highlights from our new Drill Down Report on Permian-to-Gulf infrastructure projects. 

In just a few years, the Uinta Basin has morphed from a quirky, waxy-crude curiosity to a burgeoning shale play with production north of 170 Mb/d and initial production (IP) rates that compare favorably with the best wells in the Permian. Still, there are a host of logistical challenges associated with transporting waxy crude out of the basin and questions have remained about the Uinta’s potential for growth and its staying power. In today’s RBN blog, we begin an in-depth look at the basin — with an assist from our friends at Novi Labs, whose innovative use of AI and machine learning provides valuable insights. 

The U.S. propane market may appear seamless at times, but a lot is happening just below the surface to determine consumer pricing. Key factors include the high seasonality of demand, supply contracts that must account for the seasonality of product delivery and the price, and the cost of transportation from terminals to bulk plants to end users. In today’s RBN blog, we will review the final delivery steps, the impact of transportation costs, and how contracts are priced.

Woodside Energy’s final investment decision (FID) on the $17.5 billion Louisiana LNG terminal was a stunner. For one thing, only 1 million metric tons per annum (MMtpa) of the project’s 16.5 MMtpa (2.2 Bcf/d) of capacity is under contract — U.S. LNG export projects typically have commitments for two-thirds or more of their output before pulling the trigger. The project will also have an outsized impact on gas flows in a region already struggling to keep up, and it may well upend plans for other projects in the works. In today’s RBN blog, we take a closer look at Louisiana LNG, Woodside’s daring development approach, and the terminal’s impacts on gas demand, gas flows and pre-FID projects.

The tide is shifting in the energy sector back toward hydrocarbons as renewables face new, big hurdles. The latest tangible sign of this shift is BP’s decision to refocus on traditional oil and gas and deemphasize renewables, which follows ExxonMobil’s and Shell’s restructuring of strategies in the same direction. The likelihood that hydrocarbon demand will continue to grow throughout this decade has reinforced the importance of E&P companies adding to their proved oil and gas reserves. In today’s RBN blog, we analyze crucial trends from the 2024 reserve reporting of the major U.S. oil and gas producers. 

The Trump administration is trying to breathe new life into the long-dormant Alaska LNG project, talking up its strengths and encouraging potential Asian customers and investors to consider it. But the project, a multibillion-dollar plan to pipe natural gas from Alaska’s North Slope to Anchorage and Cook Inlet for liquefaction and export, faces huge financial and administrative hurdles, plus the challenges of building it in Alaska’s rugged terrain and often-harsh climate. In today’s RBN blog, we’ll examine Alaska LNG’s competitive position and whether its reduced shipping costs, coupled with federal support, might be sufficient to outweigh the construction costs and other major obstacles the project faces. 

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.