

U.S. fuel supplier Sunoco announced in May that it has inked a US$9.1-billion agreement to buy Canada-based Parkland Corp., a move that would create the Americas’ largest independent fuel distributor. Sunoco would gain control of Parkland’s fleet of fueling stations and its valuable Burnaby refinery near Vancouver, BC. The deal is supported by Parkland’s largest shareholder and is slated to be voted on June 24. In today’s RBN blog, we’ll discuss this deal and what it means for Canada’s only West Coast refiner.
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.
US oil and gas rig count declined for the eighth consecutive week, falling to 554 for the week ending June 20 - a decline of one vs. a week ago according to Baker Hughes data.
For the week of June 20, Baker Hughes reported that the Western Canadian gas-directed rig count fell one to 46 (blue line and text in left hand chart below) and 11 less than one year ago.
Report | Title | Published |
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NATGAS Appalachia | NATGAS Appalachia Weekly – June 18, 2025 | 4 days 1 hour ago |
NATGAS Billboard | NATGAS Billboard - June 18, 2025 | 4 days 4 hours ago |
Canadian Natgas Billboard | Canadian NATGAS Billboard - June 18, 2025 | 4 days 4 hours ago |
Hydrogen Billboard | Hydrogen Billboard Weekly - June 18, 2025 | 4 days 5 hours ago |
Chart Toppers | Chart Toppers - June 18, 2025 | 4 days 6 hours ago |
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 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.