If you follow developments in the energy industry, you know that news about permitting for major infrastructure projects can sometimes read more like a horror story: 14 years to build an electric transmission line, a decade to get a mining permit, and the reality that some projects can be constructed in far less time than it takes to secure the required permits and work through any legal challenges. It’s a known problem with a lot of contributing factors, but no easy answers. In today’s RBN blog, we look at how permitting difficulties have become a flashpoint for all sorts of stakeholders — industry groups, environmental advocates, the general public, and politicians of all stripes. Our focus today will be on the current poster child of permitting challenges, Mountain Valley Pipeline (MVP), but we’ll also discuss how permitting setbacks complicate the development of all types of projects, from traditional oil and gas pipelines to initiatives at the heart of the energy transition.
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.
WTI inched higher on Tuesday, settling at $73.20/bbl, up $0.39/bbl. That followed a huge 5% increase on Monday, triggered by curtailed exports of about 450 Mb/d out of Iraq’s Kurdistan region due to cuts on a Turkish pipeline on Saturday following an arbitration decision that confirmed Baghdad's consent was needed to ship the oil. Crude prices are also being supported by easing of concerns about the global banking system, making a recession less likely. In early Wednesday trading, WTI is up about $1.00/bbl to the $74/bbl range. WTI stats are out this morning.
U.S. steam cracker margins for normal butane feedstock have soared over the past month moving from the least economical to most economical feedstock. As shown on the chart below, butane cracking margins have increased from a negative 12 c/lb in late February to 21 c/lb as of March 27. Ethane and propane steam cracker margins have improved by only about 5 c/lb over the same period, well below the 33 c/lb increase in the butane margin.
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Daily Energy Blog
New England’s aggressive effort to decarbonize is a tangled web. Over the past several years, the six-state region has replaced oil- and coal-fired power plants with natural gas-fired ones but most proposals to build new gas pipeline capacity have been rejected. It’s also made ambitious plans to add renewables — especially solar and offshore wind — to its power generation mix but many of the largest, most impactful projects have been delayed or canceled. And now there’s a big push to electrify space heating and transportation, which will significantly increase power demand, especially during the winter months, when New England’s electric grid is already skating on thin ice. In today’s RBN blog, we examine the region’s looming power supply challenges and how its energy transition plans may affect natural gas, LNG, heating oil and propane markets.
As U.S. LNG export project development accelerates in the coming years, a lot more natural gas pipeline capacity will be needed to supply the numerous liquefaction facilities vying for a piece of the global gas market pie. That’s particularly true for a small stretch of the Gulf Coast from the Sabine River on the Texas-Louisiana border to the Calcasieu Pass Ship Channel — where the bulk of planned export capacity additions are concentrated — even as transportation bottlenecks are emerging for getting natural gas supply to the area. To address the growing demand, a number of pipeline expansions are planned or proposed to bring more supply into the region or deliver feedgas across the “last mile” to these multibillion-dollar facilities. In today’s RBN blog, we continue our series highlighting some of these LNG-related pipeline projects, this time focusing on ones aiming to feed exports out of southwestern Louisiana.
Oil and gas production in the Shale Era is a refined, controlled process — and a far cry from the early days of wildcatting a century ago. Modern drilling typically involves multiple wells on a single well pad, with each well going through a four-stage process to produce hydrocarbons that are then separated into distinct components. In today’s RBN blog, we look at how drilling-and-completion techniques have evolved over the years, from old-school vertical wells to the highly complex strategies targeting shale areas today, and how they set the stage for hydrocarbon production and recovery.
Production of waxy crude in the Uinta Basin is up by more than half since mid-2021 and E&Ps there would like to produce more — the dense, slippery hydrocarbon is in high demand, not just by refineries in nearby Salt Lake City but also by at least a few of their Gulf Coast counterparts. Producers seem to have a handle on transporting increasing volumes of the stuff to market by truck and rail. The problem is, waxy crude emerges from Uinta wells with associated gas that needs to be piped away, the gas pipelines out of the play are nearing capacity, and addressing the takeaway constraints is a very complicated matter. In today’s RBN blog, we discuss the northeastern Utah play’s gas-takeaway concerns and the prospects for continued growth in waxy crude production.
Russia’s invasion of Ukraine in February 2022 set off a wave of repercussions in energy markets and economies the world over. The hope of the U.S. and its allies has been that international pressure and mounting sanctions would cause Russia to swiftly end the war — or at least make it very difficult to finance. But while the war rages on and Russia seems to be coping with the short-term impacts reasonably well, the long-term effects on its energy sector could be much more significant. In today’s RBN blog, we look at how Russia’s twin challenges — finding buyers for its crude oil and its refined products — are more different than they might seem and why Russia’s oil-and-refining sector is in the early stages of a sustained slowdown.
For several years now, almost all the Permian’s incremental crude oil production has moved to export markets along the Gulf Coast. Due to new pipeline capacity and shipping cost advantages, Corpus Christi has enjoyed a disproportionate share of those volumes. But the market is shifting. Pipelines to Corpus are filling up, and that is pushing more oil to Houston for export — and to Beaumont for ExxonMobil’s new 250-Mb/d refinery expansion. Unless the pipes to Corpus expand their capacity, much more oil supply will be targeting Houston, with important implications for pipeline capacity, dock capacity, and regional price differentials. In today’s RBN blog, we explore these issues and what could throw a curveball into the whole Gulf Coast crude oil market.
LNG exports will be the biggest driver of demand growth for the Lower 48 natural gas market over the next five years. After a year of oversupply in 2023, export capacity additions will help to balance the market and support gas prices in 2024 as the glut spills over into next year. Beyond 2024, higher export volumes will lead to tighter balances and price spikes. As supply struggles to keep up with new export capacity, the timing of pipeline expansions will be critical for balancing the market. The bulk of new LNG export projects are sited along a small stretch of the Texas-Louisiana coastline and more pipeline capacity will be needed to move incremental feedgas into this area and across the “last mile” to the facilities. In today’s RBN blog, we begin a series delving into the planned pipeline expansions lining up to serve LNG demand along the Gulf Coast.
Over the past five years, the North American oil and gas industry has undertaken a major strategic shift, embracing the global push to decarbonize by, among other things, emphasizing the greener emissions profile of natural gas vs. coal and taking aggressive steps to reduce the volumes of methane, carbon dioxide and other greenhouse gases emitted during the production, processing and transportation of just about every kind of hydrocarbon. It’s a real challenge, though. Operators face a seemingly endless and overwhelming set of choices about how best to approach emissions reductions, which technologies to use, which programs to join, and how to interpret new emissions-measurement data, to name a few. In today’s RBN blog, we begin a look at how operators can achieve key environmental goals while protecting — even improving — their bottom line and meeting a host of important goals, from reducing the cost of capital and managing investor pressure to improving realized prices and market access.
The lack of successful projects has long been a thorn in the side of the carbon-capture industry, with a few high-profile cases falling short of expectations for a variety of economic and technological reasons. When looking for a prime example of how a highly touted (and taxpayer-supported) project can still fall short, the Petra Nova facility southwest of Houston, which completed its three-year demonstration period shortly before being shut in 2020, often comes to mind. But now it’s just a few months away from getting another shot, courtesy of its new owner and recovering oil prices. In today’s RBN blog, we look at the impending restart of the Petra Nova project, how falling oil prices overshadowed its technical successes, and its importance to the carbon-capture industry.
Punxsutawney Phil presaged six more weeks of winter when he saw his shadow on February 2, the famous groundhog’s annual attempt to predict the arrival of spring that garners national headlines, despite his dismal 39% success rate over the last 150 years. Although we haven’t turned to rotund rodents, we spend a lot of time exploring ways to predict energy industry trends. A far more reliable way to gain early insights into E&P spending and production patterns is by analyzing the year-end results and forecasts issued by the major oilfield services firms, which release their year-end reports well before E&Ps typically do. In today’s RBN blog, we review the data and insights from the reports and conference calls of the major firms that are in constant communication with the major oil and gas producers.
Times are good indeed in the Uinta Basin in northeastern Utah, where one of the world’s most unusual — and, in many ways, most desirable — crude oils is being produced with increasing efficiency and in fast-rising volumes. Yes, production of the Uinta’s trademark waxy crude is up by more than 50% in the past year and a half, to record-shattering levels, and demand for the dense, slippery hydrocarbon, with its minimal sulfur content, next-to-no impurities and favorable medium-to-high API numbers, is up too. Waxy crude may be a pain in the butt to transport and store — it needs to be kept warm to remain in a liquid state — but it is a staple at the five refineries in nearby Salt Lake City, and at least a handful of Gulf Coast refineries want as much of the stuff as they can get their hands on because of its desirable qualities. But without infrastructure enhancements, there may be limits to how much Uinta production can grow from here, as we discuss in today’s RBN blog.
Over the next couple of years — and the next couple of decades — global supply/demand dynamics in refined products markets will be driven by two critically important factors. The first is the understandable reluctance of refiners to expand capacity in the face of climate policy and ESG headwinds. The second is a growing gap between policymakers’ aggressive energy-transition goals and the global pivot to a renewed focus on energy security brought about by the Russia-Ukraine war and worries about China’s global ambitions. These factors, which will fuel the prospects for constrained supply and higher-for-longer demand, have far-reaching implications, not only for refinery owners but also for E&Ps, midstreamers, exporters, energy industry investors and policymakers, all of whom need to gain a clearer understanding of what’s just ahead — and what’s over the horizon, just out of sight. In the encore edition of today’s RBN blog, we discuss key findings in “Future of Fuels,” a new, in-depth report by RBN’s Refined Fuels Analytics practice on everything you need to know about U.S. and global supply and demand for gasoline, diesel, jet fuel and biofuels over the short-, medium- and long-term.
It’s not the most accurately named piece of legislation, but that doesn’t mean the Inflation Reduction Act (IRA) might not have an outsized impact on everything from electric vehicles (EVs) and hydrogen production to greenhouse gas (GHG) emissions and carbon-capture projects. There’s plenty of potential for things to happen in the long run, but before then, a lot needs to get done — including the rules and regulations that will guide the IRA’s implementation. In today’s RBN blog, we look at why the IRA remains a work in progress, the critical role that rulemaking will play, and potential impediments to the law’s long-term success.
It’s been an awesome run for the Port of Corpus Christi’s crude oil export business, which captured about 60% of total U.S. volumes in 2022, up from only 28% in early 2018. But the rate of increase has slowed way down, even though shipping economics give Corpus a distinct advantage. The problem? Pipeline capacity, or more accurately, a lack thereof. The pipelines from the Permian to Corpus that were the driving force behind the Corpus export success story are filling up. The only questions are, how much time is left before the pipes are truly maxed out and what is likely to be done about it? In today’s RBN blog, we examine the data to see what it reveals about the looming capacity constraints.
Natural gas production in Western Canada has been enjoying a steady revival in recent years, heavily assisted by enormous growth in the unconventional Montney gas formation. A sizable portion of this formation lies in the westernmost province of British Columbia, but also underlies a large contiguous land area in that province which has been the subject of land access and development issues with the province’s First Nations residents. As a result of a legal decision made in June 2021, future natural gas production growth was thrown into question as new well licenses, crucial for future gas well development, were placed on hold until a new agreement could be reached. In the nick of time, a new agreement was announced last month. In today’s RBN blog, we discuss the implications on future natural gas drilling and production.