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.
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.
The OPEC+ ministerial meeting rescheduled for tomorrow (Thursday, November 30) seems to be inspiring high hopes from oil markets. WTI moved up again on Wednesday by $1.45/bbl (+1.9%) to settle at $77.86/bbl. Most of the increase is being attributed to expectations for a fresh round of supply cu
Data from the latest RBN Crude Voyager weekly report shows that a record number of VLCCs, 15, entered U.S. waters for loading in the week ended November 24th.
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Daily Energy Blog
Crude oil quality has been a hot topic lately. With the increase in waterborne activity along the Gulf Coast, a high-quality barrel is desired now more than ever. Permian WTI exports have continued to increase as production rises and refining capacity remains relatively stagnant (outside of ExxonMobil’s recent Beaumont expansion). This has resulted in more scrutiny on Permian quality and more concerns rising to the surface — both from the pockets of lower-quality WTI produced at the wellhead and from blending by market participants, as many midstream providers and traders have become efficient at capturing arbitrage opportunities. Recent WTI quality concerns have primarily been around metal content, hydrogen sulfide (H2S) and mercaptans, while nitrogen has become a major issue in the natural gas market. In today’s RBN blog, we look at the issue of mercaptans in WTI.
For the U.S. oil patch, exports are the lifeblood of today’s market. U.S. refineries are operating at more than 90% of their rated capacity and using as much domestically produced light-sweet shale oil as their sophisticated equipment will allow. That means that virtually all of the incremental U.S. unconventional light-sweet crude oil production will need to be piped to export terminals along the Gulf Coast, loaded onto tankers, and shipped to refineries overseas. In today’s RBN blog, we discuss what this undeniable link between crude oil exports and production growth means for U.S. E&Ps and midstream companies — and the future of the oil and gas industry.
It’s true, the Permian is — and will likely remain — the center of attention in the U.S. oil and gas industry, not just for its massive and still-growing production volumes but also for the ongoing consolidation among producers in the West Texas/southeastern New Mexico play. But while the Permian has dominated production and M&A activity the past couple of years, Chevron’s recently announced $7.6 billion acquisition of Denver-Julesburg (DJ) Basin-focused PDC Energy highlights the potential for producers to generate significant production and profits from other major U.S. regions, including the Rocky Mountains. In today’s RBN blog, we analyze Chevron’s latest mega-deal and its impacts on the buyer, seller, and the broader oil and gas industry.
Consider this fact: Three of every five barrels of crude oil produced in the U.S. are exported, either as crude oil or in the form of gasoline, diesel, jet fuel or other petroleum products. Sure, large volumes of crude and products are still being imported, but the net import number is dwindling toward zero — and if you count NGLs (ethane, propane, etc.) in the liquid fuels balance, the U.S. has been a net exporter since 2020. Yes, folks, exports are now calling the shots, and the role of exports is only going to become larger over the next few years. In today’s RBN blog, we discuss highlights from our new Drill Down Report on crude oil and product exports and why they matter more now than ever.
There is no debate about it: The CME/NYMEX domestic sweet (DSW) crude oil futures prompt-month contract at Cushing, OK, is the most closely followed benchmark in U.S. energy markets. It’s the price quoted in nightly news reports and general media publications. And now, with U.S. exports of WTI deliverable on the Brent contract, domestic sweet at Cushing is arguably setting the price for crudes around the world. But the fact is, most crudes traded in physical markets across North America are not priced at the DSW-at-Cushing benchmark but instead at a differential to Cushing — higher or lower on any given day based on each crude’s unique quality, location, and supply/demand characteristics. In today’s RBN blog, we discuss how the behavior of differentials from the Cushing benchmark can go a long way to explain what is happening with crude oil production, transportation volumes, storage and, of course, exports.
The energy industry’s upstream products — crude oil, natural gas and NGLs — are commodities, so the lowest-cost producers generally do best, especially if they are well-connected to downstream markets. Due in large part to the intensity of competition, finite drilling locations, the constant need for capital investment and the chilling effect of political headwinds, the industry is in the middle of a consolidation cycle that has enabled a select group of top-tier E&Ps to build scale — and longer-lasting inventories — in the most productive parts of the most lucrative shale plays. That scale, in turn, helps these Shale Era winners reduce their costs, gain market share and — important in 2023 and beyond — return a big slice of their free cash flow to investors as dividends and stock buybacks. In today’s RBN blog, we discuss what’s driving that “urge to merge” and what it means for industry players large and small.
It’s been two and a half years since Energy Transfer submitted its plan for the Blue Marlin crude oil export project to the U.S. Maritime Administration (MARAD) and, like the large billfish for which the proposed offshore terminal is named, the project has spent most of its time under the surface and out of sight. But that doesn’t mean there hasn’t been forward movement on the regulatory and business fronts and, with U.S. oil exports rising fast and a preference among many shippers for VLCCs that can be fully loaded without reverse lightering, Blue Marlin is alive and kicking, as we discuss in today’s RBN blog.
Since the start of this year, Canadian heavy crude oil prices have been steadily improving relative to the light crude oil benchmark of West Texas Intermediate (WTI). Improved access to and through the U.S. as far south as the Gulf Coast has contributed to these better conditions. At the same time, the traditional driver of increasing refinery demand after the end of the most recent maintenance season is being aided by the restart of two Midwest refineries that have typically been consumers of Canadian heavy oil. With international competitive pressures also easing and export buyers remaining active in the Gulf Coast, heavy oil prices could remain in a sweet spot for a good portion of this year. In today’s RBN blog, we look at why international competition for Canadian heavy crude will only intensify next year as vastly increased export access from Canada’s West Coast becomes available.
In the past, Canadian heavy oil was all too often the sick man of the North American oil market. Plagued by a limited number of refinery outlets and numerous episodes of insufficient pipeline export capacity from Western Canada, it was often subject to far larger price discounts versus the light crude oil price benchmark of West Texas Intermediate (WTI) than was justified by quality and pipeline transportation costs alone. In the past few years, however, improved pipeline export capacity to and through the U.S. has expanded the number of refineries Canadian heavy oil can reach, and the expansion of crude oil export terminals along the Gulf Coast has resulted in greatly improved exposure for Canadian barrels to buyers in international markets. The end result has been a closer alignment of Canadian heavy oil pricing in its home base of Alberta with those in the Midwest and Gulf Coast.
May the 4th be with you! Today — Star Wars Day to many of us — we borrow (and bastardize) one of the most memorable quotes from that epic collection of movies, “May the Force be with you,” to make the point that, like the “Force” that shapes events in the Star Wars universe, for the U.S. oil patch, exports are the lifeblood of today’s market. U.S. refineries are operating at more than 90% of their rated capacity and using as much domestically produced light-sweet shale oil as their sophisticated equipment will allow. That means that virtually all of the incremental U.S. unconventional light-sweet crude oil production will need to be piped to export terminals along the Gulf Coast, loaded onto tankers, and shipped to refineries overseas. In today’s RBN blog, we discuss what this undeniable link between crude oil exports and production growth means for U.S. E&Ps and midstream companies — and the future of the oil and gas industry.
Though much smaller in scope than the oil-and-gas producing behemoth of Western Canada, oil production from the offshore of Canada’s easternmost province of Newfoundland and Labrador already has decades of experience behind it. With five offshore fields producing a little under 230 Mb/d as of early 2023, the region’s slow decline is likely to continue unless existing fields undertake additional development work or new fields are discovered. Building on the province’s commitment to double output by the end of this decade, it has worked with various offshore operators to enhance its royalty regime for two existing sites that will generate increased production in the next few years. In addition, one major discovery has the real potential to meet the pledge of doubling output by the early 2030s. In today’s RBN blog we consider the history of the region’s offshore oil production and future plans to increase output.
The Shale Revolution transformed the U.S. oil and gas industry operationally and functionally in the late 2000s and early 2010s, but the most significant changes occurred years later. Through the middle and latter parts of the last decade, E&Ps continued to improve their drilling-and-completion techniques and significantly increased production as they gained experience. This production growth was enabled by — or driven by, depending on the perspective — midstream companies’ aggressive efforts to build out the pipelines, gas processing plants and other infrastructure required to handle higher production volumes and exports. More recently, capital market constraints, the Covid pandemic and a looming ESG narrative have propelled the industry into the next phase of its evolution, highlighted by fiscal discipline, which delivers improved shareholder returns through managed capital spending. But how long will this stage last — and what’s next? In today’s RBN blog, we examine the energy industry’s maturation and the differences between this transformation and those in other industries.
For a major oil and gas producer, organic growth over time is all well and good. But if you want next-level scale — and the economies that come with it — there’s nothing like cannon-balling into the deep end of the pool with a huge, game-changing acquisition. ExxonMobil has already done that twice — first in 2010 with the $41 billion purchase of XTO Energy, then in 2017 when it bought the Bass family’s oil and gas assets for $6.6 billion. Now it’s said to be poised for another big plunge, and to be eyeing the Permian’s largest E&P, Pioneer Natural Resources. In today’s RBN blog, we analyze a potential deal that would make Exxon the dominant producer in the premier U.S. shale play.
Russia has long been a significant supplier of refined intermediates and finished products to Europe, just as it has been of crude oil. That changed, however, in the wake of Russia’s invasion of Ukraine in February 2022 as the European Union (EU) implemented a formal embargo on imports of Russian crude oil in December 2022, followed by refined products in February 2023. In today’s RBN blog, we review the reduction in imports of Russian refined products and intermediates into Europe and the specific replacement sources.
It’s not just the upstream side of the Permian that’s in the midst of a major consolidation. Over the past couple of years, a slew of significant M&A deals have been made in the midstream space, most recently Energy Transfer’s $1.45 billion plan to acquire Lotus Midstream. Backed by private equity, Lotus has assembled an impressive array of crude-oil gathering, storage and long-haul pipeline assets in West Texas and southeastern New Mexico — including the Centurion pipeline system that links the Permian with the crude oil hub in Cushing, OK. In today's RBN blog, we discuss the deal and what it means for Energy Transfer, whose role in the U.S.’s most prolific crude-oil-focused production area is poised to expand by leaps and bounds.