Merger activity this year has been frequent in Canada’s oil and gas sector as companies strive for scale and efficiencies in an increasingly competitive landscape. The latest M&A salvo arrived in late August when MEG Energy agreed to a takeover offer from Cenovus Energy to create the largest bitumen producer in Alberta’s oil sands. With billions of barrels of reserves up for development, it is a chance for Cenovus to further consolidate and expand its existing lead in bitumen output from the oil sands. However, what might seem a straightforward corporate merger has been buffeted by a rival bid from Strathcona Resources in its attempt to create scale and ensure its own long-term competitiveness. In today’s RBN blog, we’ll examine the details of the two offers and what is at stake for all involved.
Daily Energy Blog
The refining industry is complex and unpredictable. Recent plant closures in the U.S. and abroad, as well as mounting pressure to produce more renewable diesel (RD) and sustainable aviation fuel (SAF), have shifted the landscape. In addition, an eight-year battle over CITGO’s three U.S. refineries has taken a new direction. Despite these shifts, the refining industry has remained resilient. In today’s RBN blog, we’ll discuss how refineries balance these changes and make choices to shape their future, the focus of our upcoming Refined Fuels Master Class. Warning: Today’s blog is a blatant advertorial.
Strong demand for refined products (especially jet fuel) in Arizona and refinery closures in Southern California have spurred the development of a new refined products pipeline from West Texas to the Phoenix area. ONEOK, whose acquisition of Magellan Midstream Partners made it a player in refined products, has announced an open season for the proposed Sun Belt Connector pipeline, which would expand PADD 2 and PADD 3 refiners’ access to premium markets out West. In today’s RBN blog, we discuss ONEOK’s plan and how it could impact refined products markets.
North America is an integrated energy market so deeply connected that it functions as one massive, interdependent system for the three “drillbit hydrocarbons”: crude oil, natural gas and NGLs. But the rapid changes happening in the market now — driven not only by supply/demand dynamics and evolving infrastructure but also regulatory policies and political pressures — mean it’s more important than ever to talk about how the ongoing relationship between the U.S. and Canada will evolve and strengthen in the coming years. That was the focus of our School of Energy Canada and the subject of today’s RBN blog. Warning: Today’s blog includes some blatant plugs for a newly available replay of our recent conference in Calgary.
Which is true, A or B? (A) Data center demand to power AI applications is the most transformative force to hit energy markets in years, or (B) This is one of the most overhyped, inflated narratives ever. We hear a constant stream of announcements, promotions and proclamations from developers, tech giants, utilities and politicians, many predicting a revolutionary surge in electricity and gas demand that will change everything. At the same time, others warn of a speculative bubble destined to pop. As we discuss in today’s RBN blog, sorting out which side is closer to reality is one of the most important questions facing U.S. energy markets.
For most of us, matching spending with income is the logical path to financial stability. However, after decades of aggressive investment in search of growth, the “dollars in equals dollars out” method of allocating free cash flow has been an adjustment for many U.S. oil and gas producers. Their post-pandemic concentration on keeping capital spending well below inflows, maintaining healthy leverage ratios and directing excess funds to reward shareholders with dividends and stock buybacks has revitalized the industry and restored investor confidence. But ebbing commodity prices have upped the difficulty of this quarterly zero-sum game. In today’s RBN blog, we will analyze the shifts detected in Q2 2025 cash allocation of the 38 major U.S. E&Ps we cover.
After a decade of regulatory and legal challenges, Mountain Valley Pipeline (MVP) finally came into service in the middle of last year. The 2-Bcf/d pipeline — soon to be expanded to 2.5 Bcf/d via additional compression — was designed to ease natural gas takeaway constraints out of the Marcellus/Utica and help production there break past its current plateau near 36 Bcf/d, but bottlenecks on the massive Transco Pipeline have complicated matters. In today’s RBN blog, we look at efforts to unleash more Appalachian gas in the domestic market, focusing on the Southside Reliability Enhancement Project (SREP), which has enabled more gas to reach North Carolina.
Refineries in Europe, Latin America, Russia and China are facing a host of issues that could ultimately benefit U.S. refiners. Europe has high operating costs and political pressures. Attacks have damaged Russia’s refineries, and the country continues to get blasted with steeper sanctions. China’s aging plants are closing and there are no new large-scale projects on the horizon. Latin America lags in capacity growth. In today’s RBN blog, we look at how these global issues are boosting opportunities for U.S. refiners.
Crude oil production in the Permian may or may not have peaked — that’s TBD. What we do know is that even if the shale play’s oil output flatlines, the Permian will generate increasing volumes of natural gas (and NGLs) and virtually all of it will need to be piped to other markets, primarily the Gulf Coast to feed existing and planned LNG export terminals, gas-fired power plants and other large consumers. To keep pace with that undeniable need for more Permian-to-Gulf takeaway capacity, WhiteWater has announced plans, through its Matterhorn joint venture (JV), for yet another mountain-themed gas conduit to the coast. In today’s RBN blog, we discuss WhiteWater’s newly unveiled Eiger Express Pipeline.
U.S. interstates are populated with electronic displays that update drivers in real-time on traffic conditions, road closures, weather alerts and other important events. If there was a sign for executives steering our nation’s oil and gas producers, it would likely read “Poor Visibility, Slow Down Ahead.” After a short-lived price rally in Q1 2025, the industry faced lower commodity realizations and macroeconomic headwinds in Q2 2025, which spooked investors and hardened a cautious investment approach. In today’s RBN blog, we analyze the latest results of the 39 major U.S. E&P companies we cover and look at what’s ahead.
The fact is, many major E&P acquisitions include at least some production assets that don’t align with the acquiring company’s long-term strategic plans. Also, it’s often true that big-dollar M&A increases the buyer’s debt level — and it’s typical in such cases that the company commits to quickly reducing its debt through the divestiture of non-core assets. As we discuss in today’s RBN blog, there’s a lot of that going on now, and in many cases smaller, private-equity-backed producers are scooping up the acreage and production being sold.
Midstreamers developing natural gas takeaway capacity out of the Permian have understandably focused on pipelines to the Gulf Coast — and along the coast to LNG export terminals and other big gas consumers. But don’t forget the Desert Southwest, where demand for gas-fired power is soaring. Energy Transfer recently committed to building a 516-mile, 1.5-Bcf/d expansion to its Transwestern Pipeline system from West Texas to the Phoenix area, and hinted that it might double the project’s capacity due to the high level of interest. In today’s RBN blog, we discuss Energy Transfer’s aptly named Desert Southwest Project, what drove its quick progress to a final investment decision (FID), and what other westbound projects out of the Permian might still happen.
Crude oil production in the Permian may or may not have peaked — that’s TBD. What we do know is that even if the shale play’s oil output flatlines, the Permian will generate increasing volumes of natural gas (and NGLs) and virtually all of it will need to be piped to other markets, primarily the Gulf Coast to feed existing and planned LNG export terminals, gas-fired power plants and other large consumers. To keep pace with that undeniable need for more Permian-to-Gulf takeaway capacity, WhiteWater has announced plans, through its Matterhorn joint venture (JV), for yet another mountain-themed gas conduit to the coast. In today’s RBN blog, we discuss WhiteWater’s newly unveiled Eiger Express Pipeline.
In the U.S., crude oil trading hubs like Houston, Midland and Cushing get the lion’s share of the market’s attention. But travel a bit further north and you can find one of the more unusual and liquid crude markets in the country — Guernsey, WY — a focal point for producers in Western Canada, North Dakota, Wyoming, Utah and Colorado. Over the last few months, Guernsey differentials have tightened significantly, finally flipping to a premium to Cushing. We have seen this phenomenon occur before, most notably seven years ago after the startup of the Dakota Access Pipeline (DAPL). In today’s RBN blog, we discuss the recent movement in Guernsey differentials and what the future could hold for the often-overlooked sales point.
As demand for data centers accelerates, developers continue to search for locations that offer the best combination of several factors, starting with the availability of uninterrupted (and affordable) power. Those variables have led to a data-center buildout in several parts of the U.S., such as Northern Virginia, Texas and California’s Silicon Valley, but Canada has its own set of positives to lure developers. In today’s RBN blog, we look at the state of data-center development in Canada, how the factors that affect site selection differ from the U.S., and how Canada is working to become a bigger player in the global market.
