Alkylate is an important and valuable part of the U.S. gasoline pool, prized for its high octane, low volatility and low sulfur content. There are two primary catalysts that refiners can opt to use in the production of alkylate: hydrofluoric acid, or HF, and sulfur acid, or H2SO4. Each is quite popular, with HF and sulfuric acid technologies each representing about half of domestic alkylation capacity — and with those shares varying significantly on a regional basis. While refiners have been safely operating both types of “alky” units for many decades, HF alkylation for some time has been in the crosshairs of the Environmental Protection Agency, which recently proposed that refiners be required to undertake extensive evaluations of potentially safer alternative technologies. It’s hard to know for sure, but if EPA’s proposed rule is made final it could ultimately force many refineries to make very costly changes — into the hundreds of million dollars per unit — or maybe even shut down entirely. In today’s RBN blog, we look at alkylate, how it’s made, and the potentially profound effects of the impending regulation.
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In days gone by, the common sentiment in the oil patch when prices rose was “Drill, baby, drill!” Not only have times changed, but even back when the phrase was made famous by former Republican Vice-Presidential nominee Sarah Palin in 2008 it vastly oversimplified and understated the efforts required to secure new production. It’s easy to overlook how intensive (and time-consuming) the operation at a well site is before even being able to extract any of those precious crude oil, natural gas and NGL molecules found beneath our feet. Prior to hydrocarbon production, well sites must be obtained, tested and developed by exploration and production companies trying to determine their chances of making a reasonable return on their investment. In today’s RBN blog, we take a step-by-step look at the leasing process.
The recently passed Inflation Reduction Act (IRA) offers a lot of incentives, mostly in the way of tax credits, to advance the Biden administration’s clean-energy initiatives and reduce greenhouse gas (GHG) emissions. There are inducements for everything from carbon capture and electric vehicles to renewable energy and hydrogen production, but very few penalties. One exception is included in the new law’s Methane Emissions Reduction Program (MERP), which features the federal government’s first-ever fee on the emissions of any GHG. In today’s RBN blog, we look at recent attempts to mitigate methane emissions, how the new methane charge will work, and how it could one day be replaced by new federal rules.
Last week, the U.S. Department of Energy (DOE) unveiled its timeline for receiving and reviewing proposals to develop six to 10 clean-hydrogen hubs and said its aim was to decide by the fall of next year which projects will share up to $7 billion in DOE support. The competition for those dollars is sure to be fierce, with some of the strongest proposals likely to come from states like Texas and California that have a lot of renewable energy and ambitions to be leaders in the energy transition. Also, there is a joint effort by three states east and north of Texas to develop a hydrogen hub that would take advantage of their existing and planned hydrogen-production and wind assets, natural gas supply, refinery and pipeline infrastructure, and carbon sequestration potential. In today's RBN blog, we discuss the DOE's recent announcement and the three-state hydrogen-hub plan, which is dubbed H2ALO.
The world needs more LNG and the U.S. is answering that call. Two U.S. liquefaction projects, Venture Global’s Plaquemines LNG and Cheniere’s Corpus Christi Stage III, have already reached a final investment decision (FID) on a combined 23.3 MMtpa (3.1 Bcf/d) of export capacity, which will be online by mid-decade. But by the looks of it, we are just getting started. Next up could be NextDecade’s Rio Grande LNG, which has sold 75% of its first two trains’ capacity — enough to take FID, possibly by the end of the year. If it moves forward, not only will the project add another 10.8 MMtpa (1.43 Bcf/d) or more of export capacity to the Gulf Coast, it could also come with a new carbon capture and sequestration (CCS) facility, which has long been a selling point for the project. In today’s RBN blog, we continue our series on the U.S. LNG projects most likely to move forward, this time with a look at Rio Grande LNG.
The battle to restore energy reliability in Europe has breathed new life into North American LNG export projects — and into the Haynesville Shale in Louisiana, the closest supply basin to many of the planned and proposed liquefaction facilities. Gas production in the region has climbed more than 4 Bcf/d — an impressive 39% — since 2019 and we expect it to grow nearly as much over the next three years. The big question on everyone’s mind, however, is whether there will be enough pipeline capacity to move that gas to where it’s needed on the coast. Pipeline capacity for southbound flows through the Bayou State is already showing signs of stress. Will recently completed and upcoming debottlenecking projects help stave off major supply and pricing disruptions? In today’s RBN blog, we provide our outlook on Haynesville production and the nature and timing of Gulf-bound pipeline projects.
There finally seems to be some momentum building for additional LNG export projects on Canada’s West Coast. Major pipeline and midstream operator Enbridge announced in late July that it was making an investment in Woodfibre LNG, a smaller-scale export project that has already come a long way in terms of approvals, pipeline connections, locking up gas supplies, and initial financing. With the Enbridge announcement — and the financial and technical clout the company brings to the table — it is now looking assured that the project will commence construction next year and be exporting LNG by 2027. In today’s blog, we take a detailed look at Woodfibre LNG.
Economic sanctions can be a powerful tool to punish a country or group, especially if they involve an essential commodity like crude oil. Imposed for a variety of reasons (military, political, social), sanctions can cause serious harm to the targeted entity. But levying them effectively is not as simple as it may seem, and even the most well-intentioned plans can fall short or have unintended consequences or backfire altogether. In today’s RBN blog we look at a plan by the U.S. and its allies to limit the price of Russian crude oil and the significant challenges in designing a cap that is effective and enforceable.
It’s been another tumultuous few months for natural gas prices, particularly amid what European Commission President Ursula von der Leyen has called Russia’s war on Europe’s energy and economy. Europe is staring down aggressive curtailments of Russian gas supplies and rising consumer utility bills, necessitating austerity measures and beyond to bail out consumers and utilities and prevent a dangerous shortfall this winter. Prices in continental Europe have now topped $20/MMBtu for a year, higher than the previous single-day record. On top of the elevated prices, outrageous spikes higher and lower have become a semi-regular occurrence as the gas market struggles to find balance. And high prices and volatility are not going anywhere anytime soon as Europe braces for a winter with little or even no Russian gas. In today’s RBN blog we look at European gas prices, the latest energy policy proposal from the EC and how U.S. LNG exports fit into the ongoing crisis.
The high cost of gasoline and diesel and their impact on inflation and the global economy has been a major market development this year, with the blame typically being cast on politicians, oil producers and policies intended to limit development of traditional energy resources and encourage decarbonization — and sometimes all of the above. Prices have retreated in recent weeks amid lower consumer demand and worries about the state of the global economy, but long-term concerns about global refining capacity and the possibility of another price spike remain. In today’s RBN blog, we discuss highlights from our new Drill Down Report on the state of global refining.
Lower 48 natural gas production this month hit a once-unthinkable milestone, topping the all-important psychological threshold of 100 Bcf/d for the first time. Volumes have remained at record highs through mid-September, with year-on-year gains expanding to a breathtaking 7-9 Bcf/d above last year at this time (when hurricane-related shut-ins were in effect). The record production levels coincided with a seasonal decline in weather-related demand, as well as the ongoing outage at the Freeport LNG export terminal. Remarkably, however, even with all-time high, ~100 Bcf/d natural gas production and Freeport LNG offline, the Lower 48 gas market balance averaged tighter year-on-year — a testament to just how strong consumption has been lately, and for much of this summer for that matter. In today’s blog, we look at how the supply-demand balance has shaped up this month and where it’s headed near-term.
What has been the most controversial topic in the U.S. refining industry over the last 10 years? Well, it’s a matter of opinion but, judging from time spent in earnings conference calls, law offices, courtrooms, congressional committees, the White House, and other forums of business and political debate, Renewable Identification Numbers — or RINs — would have to be a top contender for that prize. In today’s RBN blog and the final episode of this series, we consider two differing viewpoints on the effects of the RIN system and specific disagreements — or are they misunderstandings? — about the financial consequences of RINs that have dominated the debates and legal cases.
With international gas prices ranging somewhere between ridiculous and ludicrous since last fall, the entire global trade of LNG is going through an unprecedented period of change as gas-consuming nations try to cope with the current situation and seek protection from tight supplies and high prices in the future. The problems of Europe in securing supplies for the imminent winter have been well documented here and elsewhere in the trade press. In addition to being a major struggle for consumers and a headwind to economic development, there are also numerous, less-obvious consequences of the tectonic shifts in gas fundamentals, including countries’ individual plans for long-term energy supplies, potential tax-related issues, the contractual structures used to transact LNG, and even the assessments of the commodity price itself. These issues aren’t new and, in many cases, have been discussed for years. What’s changed is that extremely high prices have thrown into sharp relief any inefficiency or risk that exposes market participants. In today’s RBN blog, we consider the impact of high global gas prices on countries in Asia and Europe and how pricing mechanisms might be affected.
Refined product markets in the U.S. are constantly morphing. Over time, demand for gasoline and diesel rises or falls, refineries are shut down, and the price spread between products sold in neighboring regions widens or narrows. These changes can incentivize refiners and marketers to push into new areas — and encourage midstream companies to develop pipeline capacity to ease the flow of gasoline, diesel and jet fuel into newly attractive markets. Midstreamers have advanced a number of pipeline projects in the past few months to help move increasing volumes of products west across Texas to the Permian, the Great Plains and into the Rockies. In today’s RBN blog, we discuss these projects and what’s been driving their development.
The U.S. natural gas market is one of the most transparent, liquid and efficient commodity markets in the world. Physical trading is anchored by hundreds of thousands of miles of gathering, transmission and distribution pipelines, and well over 100 distinct trading locations across North America. The dynamic physical market is matched by the equally vigorous CME/NYMEX Henry Hub natural gas futures market. Then, there are the forward basis markets — futures contracts for regional physical gas hubs. These pricing mechanisms play related but distinct roles in the U.S. gas market, based on when and how they are traded, their respective settlement or delivery periods, and how they are used by market participants. In today’s RBN blog, we continue a series on natural gas pricing mechanisms, this time with a focus on the futures and forwards markets.
Massive shifts are occurring in the U.S. crude oil export market, but you wouldn’t know it from the steady-as-she-goes pace of activity. The volumes being loaded along the Gulf Coast have stayed within a relatively tight range — 2.5 MMb/d to 3.2 MMb/d — for 12 consecutive quarters now, and the export pace for each of the past three quarters has remained within a few thousand barrels of 3 MMb/d. So, what’s changed? For one thing, Corpus Christi is now by far the dominant point of export, with Houston, Louisiana, and Beaumont/Nederland trailing. Another is that Europe, heavily impacted by the sharp decline in imports from Russia, is now the leading destination for U.S. barrels. There are other changes, too, including increased use of Very Large Crude Carriers (VLCCs) and terminal expansion projects. In today’s RBN blog, we discuss highlights from our recently published Crude Voyager Quarterly Report.