Global natural gas prices are once again at record levels as escalating tensions between Russia and the Western world have re-ignited fears over gas shortages in Europe this winter. The global gas market is in the midst of an epic bull run that has been going on for more than a year, taking prices from all-time lows in the summer of 2020 to repeated all-time highs. And while strong demand for gas and LNG has underpinned prices and tied global gas markets together, Europe has been the driving force behind most of the headlines and panic-driven price run-ups. Prices in Europe have climbed to nearly $60/MMBtu as market fears around Russian gas supplies into Europe have been renewed by threats of new U.S. sanctions on Russia over aggression toward Ukraine, delays to the startup of the controversial Nord Stream 2 pipeline, continued low gas flows from Russia to Europe on existing infrastructure, and now Europe is facing its first real cold snap of the season. In today’s RBN blog, we take a look at the situation in Europe and its impact on the global gas and LNG markets.
Daily Energy Blog
A few things have changed since we wrote our first hydrogen blog a year ago. First, there’s heightened awareness of the many ways hydrogen can be used to help reduce greenhouse gas (GHG) emissions. Second, the number of proposed hydrogen production projects has proliferated, and our project list continues to grow each week. Third, and perhaps most importantly, the federal government has thrown its support — and billions in taxpayer dollars — behind low-carbon hydrogen. However, despite those positive developments, hurdles clearly remain in the hydrogen sector, with economics a major sticking point, though a few projects are set to get off the ground next year. In today’s RBN blog, we provide a year-end update on domestic hydrogen projects.
It may seem like a strange turn of phrase, but the best way to describe the E&P sector’s recent round of quarterly earnings calls is a celebration of remarkable climate change. Buffeted and nearly swamped over the past few years by price volatility, investor revolt, regulatory restrictions, and a global pandemic, oil and gas producers finally have the opportunity to bask amid robust returns in an increasingly sunny economic environment. E&Ps are enjoying higher profits and massive free cash flow, raising their dividends, and looking forward to 2022 with renewed optimism. In today’s RBN blog, we outline the dramatic recovery of E&Ps since mid-2020, examine the surge in third-quarter results, and look ahead to the next round of earnings calls this winter.
Japan’s strategy for LNG imports has been based on security and reliability of supply, with JERA, the country’s largest LNG buyer, reliant on supply contracts that can last for 20-25 years. Those deals have been of paramount importance since imports to Japan started in 1969, but things are changing in a big way. In parallel with Japan’s plan to decarbonize its economy, JERA has made clear its intention to reduce its dependence on long-term LNG contracts and instead focus more on short-term deals supplemented by spot market purchases. This decision will have several important effects, and in today’s RBN blog, we look at what it may mean for the LNG industry.
Way back in the spring of this year, propane prices were behaving themselves. Mont Belvieu values were high relative to the previous two years, but no higher than what they ought to be with crude oil up to the mid-$70s/bbl range, as it was back then. Yet, market players were uncomfortable. Production was flat, exports were strong, and inventories were not increasing fast enough to get balances where they needed to be by winter. At that point the market got nervous and started bidding the price of propane higher. When exports continued at high rates and it looked like $100/bbl crude was a real possibility, propane buyers went into a feeding frenzy, and by early October propane prices blasted to levels not seen in a decade. Then the market calmed down. Weekly inventory numbers from EIA started to look like they might be OK after all, exports backed off, and propane prices started to decline. That’s supposed to happen toward the end of heating season, not at the beginning. The frenzy soon turned into a rout in a counter-seasonal price move egged on by concern about the COVID-Omicron variant that saw propane collapsing by 35% over a five-week period. All that price action happened during the summer and fall, instead of during the winter, as it usually does. We just got ahead of ourselves. So, what happens next? That is what we will consider in today’s RBN blog, which is Part 2 of our Different Drum NGL blog series.
In early December, natural gas production in the Permian has been averaging a record 14.2 Bcf/d, a gain of 1 Bcf/d in only six months. That rapid pace of growth is putting pressure on every aspect of midstream infrastructure — gas gathering systems, processing plants, and takeaway pipelines — and resulting in a variety of efforts aimed at ensuring there will be sufficient capacity in place to support the increasing gas volumes being produced. New gas-gathering mileage is being added, some new processing plants are being built, and at least a couple of new large-diameter pipelines from the Permian to the Gulf Coast are being considered. However, reflecting the midstream sector’s financial discipline, there’s also a big push to make fuller use of existing assets, in some cases by relocating processing plants, compressors, and other assets to where they are needed most. In today’s RBN blog, we discuss the latest gas-related infrastructure developments in the Permian’s Midland and Delaware basins.
There’s been a lot of talk lately about “green” and “blue” hydrogen becoming increasingly important players in the world’s lower-carbon energy future. Green and blue ammonia too, given that ammonia, with its high hydrogen content, is an efficient “carrier” of hydrogen when it needs to be delivered by ship, railcar, or truck. Also, ammonia itself — like hydrogen — can be used to power fuel cells and ammonia-combustion technology is being developed to use fuel ammonia at power plants. But for these low- or zero-carbon energy products to be adopted at a global scale, new infrastructure will need to be built, not only to enable their production and consumption but to transport them to where they’ll be consumed. Enter the just-finished ammonia terminal that Royal Vopak and Moda Midstream jointly developed at a prime site along the Houston Ship Channel. In today’s RBN blog, we discuss the greenfield facility and its prospective role as a major import/export hub for ammonia.
It has been an epic year for U.S. LNG. After COVID-19 and the subsequent global market crash brought LNG development to a standstill and shut-in production from existing terminals in 2020, this year has seen global prices repeatedly smash previous record highs, driving existing terminals to operate at peak levels and renewing interest in new LNG buildout. U.S. feedgas demand and LNG production will close out the year at all-time highs, but with just a few weeks left it looks like 2021 will be the first year since 2017 that no new LNG terminals will achieve a positive final investment decision. But that’s driven more by the tailwinds of 2020 — the back half of 2021 has seen a tremendous amount of commercial activity in the LNG sector. More than 21 million metric tons per annum of medium- and long-term capacity from planned LNG projects has been sold this year, creating enough forward momentum for multiple projects to move toward FID in 2022. We cover all the latest developments in our LNG Voyager Quarterly report, and in today’s RBN blog we take a look at some of the recent LNG deals and what they tell us about the future of North American LNG.
Trans Mountain Pipeline, the only pipeline that connects crude oil production areas in Alberta to Canada’s West Coast and the U.S. Pacific Northwest, has started to resume operations after a three-week shutdown. The pipeline closure — the longest in TMP’s 68-year history — began November 14 after major flooding exposed portions of the 300-Mb/d conduit, which also carries some refined products. Fortunately, Trans Mountain did not suffer any severe damage, breaks, or spills, and its operators were able to initiate a phased restart on December 5 at reduced pressures. Full service is expected to be restored soon. So what happens when a primary source of crude oil to five refineries — four in Washington state and one in British Columbia — is removed from service with little notice? In today’s RBN blog, we discuss the impacts.
Market sentiment toward oil and gas companies, particularly producers and midstreamers, has been increasingly negative since the oil price crash in late 2014, driven by a mix of shorter-term concerns like price volatility and corporate debt and longer-term worries like the environment and an impending energy transition. One company that has found it especially difficult to regain investor confidence is midstream giant Kinder Morgan Inc., whose late-2015 decision to slash its dividend got an ice-cold reception from shareholders and sent the company’s stock price sharply lower. Over the past six years, KMI has been largely successful in its efforts to stabilize its balance sheet, internally fund growth, and gradually restore its dividend, but its current share price remains close to its late-2015 low and barely one-third its early-2015 high. In today’s RBN blog, we discuss highlights from our new Spotlight report, which analyzes KMI’s current portfolio and performance and discusses in detail the company’s new strategic initiatives to restore investor confidence.
International shipowners need to significantly reduce their carbon-dioxide emissions by 2030 and will come under pressure to achieve carbon neutrality by 2050. Given that the industry currently depends almost entirely on fossil fuels for ship propulsion — and that every zero- or near-zero-carbon alternative faces serious headwinds — it won’t be an easy or low-cost transition. One pathway would be expanding the use of LNG as a bunker fuel in the near term and then shifting to alternatives like bio-LNG and synthetic LNG as they become more commercially available and economic. Another would be to use “green” or “blue” hydrogen, ammonia, or methanol. But there are challenges to each, not the least of which are the small volumes of non-traditional fuels being produced — and their high cost — and the need for new infrastructure both to produce and distribute them, as we discuss in today’s RBN blog.
It’s no secret to anybody paying attention to U.S. natural gas markets that Appalachia has long been bedeviled by midstream constraints, often leading to deep gas price discounts. There have been brief respites when new capacity has come online, allowing more gas to flow out, but if you've been reading our blogs and natural gas reports lately, you know we've been sounding the alarm about the growing specter of constraints reemerging. Across the country, the boom in pipeline reversals, greenfield projects, and pipeline expansions that characterized much of the 2010s is pretty much over, with just a couple of approved expansions left, and it’s gotten much harder for projects offering additional capacity to gain traction, especially in the Northeast. In today’s RBN blog, we consider the big questions facing the region: how fast will Appalachian gas production grow, how much running room do producers have left, and what are the implications of midstream constraints for forecast supply growth?
Late last month, the Canada Energy Regulator (CER) ruled against Enbridge’s proposal to convert as much as 90% of the capacity on its multi-pipeline, 3-MMb/d Mainline crude oil system to long-term contracts. The CER’s action leaves in place the Mainline’s current capacity-allocation process, under which every barrel-per-day of the pipeline system’s capacity is open to all shipping customers on a month-to-month basis. Although the rejection of Enbridge’s proposal is unlikely to change the volume of Western Canadian crude oil flowing on the Mainline over the next few months, the longer-term outlook for Mainline flows is less certain given that other, competing pipeline capacity out of Alberta will be coming into service by late 2022 or early 2023. In today’s RBN blog, we examine the decision to reject long-term contracting and what might be the next steps for Enbridge.
Carbon dioxide is not the most potent of the greenhouse gases, but it is by far the most prevalent, which makes it a primary focus of efforts to protect the planet. And while a lot of attention is being paid to ways to reduce CO2 emissions and to capture those that are produced, it’s important to remember one key fact: There’s strong demand for CO2 for a variety of commercial uses, from enhanced oil recovery and fertilizers to industrial processes and beverage production. In other words, CO2 has real value to certain parts of the global economy and capturing CO2 for sale to these customers must be factored into the decarbonization equation. In today’s RBN blog, we take a closer look at the industrial CO2 value chain.
There’s been a slew of high-profile shipments of “carbon-neutral LNG” the past few months, typically involving the use of carbon credits to offset, ton-for-ton, the carbon dioxide equivalent of greenhouse gases released during the production, piping, and liquefaction of natural gas, the shipping of LNG, and often the regasification and ultimate consumption of the gas too. The problem is, there is no widely agreed-to definition for carbon neutral, nor is there a consensus on how to quantify and validate the GHG “footprint” of a specific LNG cargo. Now, an international group representing the world’s LNG importers has established a framework for “GHG-neutral LNG” that it hopes will gain widespread acceptance. Elements of the proposal are sure to be controversial, however, as we discuss in today’s RBN blog.
