Oil and gas companies across the value chain are facing new pressures to manage and reduce methane emissions. Their ability to access premium markets and buyers, appeal to investors and avoid costly fees depends on developing a credible plan to measure and reduce methane emissions. At the very least, the industry’s regulatory outlook, its non-governmental quasi-oversight and its access to capital are changing in ways that make understanding sometimes inconsistent emissions data vitally important. In today’s RBN blog, we explore the recent changes and the mounting external pressures around methane emissions.
Daily Energy Blog
For the first 10 years of the Shale Revolution, it was a foregone conclusion: High prices stimulated more drilling, and more drilling meant higher production. It worked in both directions. When prices crashed, so did production. The correlation was great. The relationships were right on cue in 2014-15 when $100/bbl crude crashed to $30, rebounded to $60 by 2019, and wiped out in 2020 when the COVID meltdown hit. But then the market shifted. As prices ramped up in 2021 — eventually to astronomical levels in 2022 — the phenomenon of producer discipline kicked in, with E&Ps capping their drilling programs and returning a significant slice of their rising free cash flow to their shareholders. The near-term market implications of this new dynamic have been extensively documented in the RBN blogosphere. But what does it mean for the future? Especially for intrepid energy analytics companies (like RBN) that, by necessity, must project producer behavior far into the future to determine what production will look like next year, next decade and even further over the horizon. In this new RBN blog series, we will examine that dilemma, the assumptions RBN makes, and what our forecasts for the next few years look like.
The numbers don’t add up. Literally. The most closely watched energy statistics in the world have a problem, and it’s been getting worse over the past two years. We’re talking about EIA’s U.S. crude oil supply, demand and inventory balances, which are published each week and then trued up about 60 days later in monthly data. The problem is that the balances don’t balance. EIA uses a plug number alternatively called “adjustment” or “unaccounted for” to force supply and demand to equate. That would not be an issue if the plug number was small and flipped frequently from positive to negative, likely due to timing inconsistencies with the input data. But that’s not the case. The number is mostly positive, meaning more demand than supply. And the difference can be mammoth: last week it was 2.3 MMb/d, or 18.4% of U.S. crude production. It seems like barrels are somehow materializing out of nowhere. But now we know where, because EIA just finished a 90-day study of the crude imbalance that reveals the sources of the problem and what it is going to take to fix it. In today’s RBN blog, we will delve into what has been causing the problem, what it means for interpreting EIA statistics, and what EIA is doing to address the issues.
U.S. production of renewable diesel (RD) is rising fast and production of sustainable aviation fuel (SAF) will soon follow suit, driven largely by federal and state incentives. But U.S. demand for both RD and SAF is growing at a more measured pace, mostly because they are throttled by a number of other governmental policies, including the level of blending mandates set by the Environmental Protection Agency (EPA). As we see it, the net effect of this disconnect between domestic supply and demand will be the U.S. becoming a net exporter of RD this year and a net exporter of SAF in 2025 — but only after a spike in SAF imports in 2023-24. Yes, it’s complicated, but with public-sector policies impacting both sides of the supply/demand scale, did you really expect it wouldn’t be? In today’s RBN blog, we look at two more energy products the U.S. will be exporting.
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.