Global gas and LNG prices are currently at record high levels. If we sound like a broken record, it’s because this epic bull run that started in the spring, has been roaring in recent weeks and showing little sign of slowing down. European prices have hit new post-2008 or all-time highs more than 25 times since late June, and prices in Asia, which had been at seasonal all-time highs for most of the spring and summer, finally last week also topped its previous all-time record from last January. A confluence of bullish factors, including high global demand, low storage inventories, weather events, and supply outages, have all contributed to the surge in gas prices. While many of these are near-term drivers and will eventually flip in the other direction, there is one bullish driver of global gas demand — European carbon prices — that will remain a constant in the years to come. That is by design because the carbon market is meant to serve as an incentive for the industry to seek greener solutions over fossil fuels. In today’s RBN blog, we look at the European Union’s Emission Trading System (EU ETS) and how it interacts with the global gas market.
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Everyone knows the old saw, “Make hay while the sun shines.” Oil and gas producers have historically honored this sentiment by boosting their capital spending when commodity prices were high and cutting back when realizations dipped. Their investment peaked in 2014, when oil prices were hovering over $100 per barrel, plunged with the price crash in 2015-16, recovered with $70 oil in 2018, and crashed again in the ugly early days of the COVID-19 pandemic. The sun is out again in 2021, but E&Ps seem to have tossed out their old mantra in favor of fiscal discipline, setting and maintaining investment at historic lows despite solid oil prices and surging gas futures. In today’s RBN blog, we review mid-year changes to E&P capital budgets and their impact on oil and gas production.
With natural gas prices reaching levels not seen in seven years, Western Canada is doing all it can to help increase gas supply, with recent data showing monthly production hitting multi-year highs. Moreover, Canadian forward gas prices are at the highest levels since 2014, gas pipeline expansions are in place or being constructed to accommodate future supply expansion, and gas-focused drilling activity remains strong — all of which may as well be a prescription for sending gas production to record levels later this year and in 2022. In today’s RBN blog, we provide an update on the recent gas production growth in Alberta and neighboring provinces and why more growth is coming.
In the recently fervent efforts of oil and gas companies to mitigate their environmental impact and improve their standing with investors and lenders, they are progressively striving to cut their own emissions of greenhouse gases and to offset the GHG emissions that are unavoidable through the use of carbon credits. Cutting emissions from well sites, pipeline operations, refineries, and the like won’t be easy or cheap, but at the least the results are measurable and provable — before, we emitted X, and now we emit X minus Y. The true value of voluntary carbon credits is more difficult to calculate. Sure, each credit is said to equal one metric ton of carbon dioxide or its equivalent, but how do you really measure with any certainty how many metric tons of CO2 will be absorbed by 1,000 acres of preserved forest in Oregon, or how much methane won’t be produced by changing the diet of 1,000 cows in Wisconsin? And how can you be sure that slice of Oregon wouldn’t have been left in place anyway, or that the dairy farmer has actually changed what he’s feeding his herd? In today’s RBN blog, we look at voluntary carbon credits, concerns about their validity, and ongoing efforts to ensure that they actually accomplish the goal of GHG reductions.
There’s a lot to like about the unusual, waxy crude oil produced in the Uinta Basin in northeastern Utah. Low production costs, minimal sulfur content, next-to-no contaminants, and favorable medium-to-high API numbers. Oh, and there’s plenty of the stuff — huge reserves. The catch is that waxy crude has a shoe-polish-like consistency at room temperature, and has to be heated into a liquid state for storage and transportation. As you’d expect, refineries in nearby Salt Lake City are regular buyers; they receive waxy crude via insulated tanker trucks. They can only use so much though. Lately, a couple of Gulf Coast refineries have been railing in occasional shipments of waxy crude, but getting it onto heated rail cars involves a white-knuckle tanker-truck drive across a 9,100-foot-high mountain pass to a transloading facility. Now, finally, crude-by-rail access from the heart of the Uinta is poised to become a reality, offering the potential for much easier access to distant markets and, possibly, a big boost in Uinta production. In today’s blog, we provide an update on waxy crude and its prospects.
Memories of disasters linger, and it’s likely that no one in the North American energy sector is likely to ever forget the second quarter of 2020. As the COVID-19 pandemic destroyed demand and crude oil prices bottomed out, exploration and production companies (E&Ps) scrambled to shut in wells and slashed spending in the face of an unprecedented plunge in average realizations to less than $14 per barrel of oil equivalent (boe). Not everyone bought into apocalyptic visions of the industry’s future that were circulating widely, but few analysts expected the rapid return to the level of profitability reflected in the recently released second-quarter 2021 results of the 39 major E&Ps we monitor. Rising oil prices and continuing cost control propelled the earnings of the Oil-Weighted and Diversified peer group companies over the results from the last industry performance peak in the third quarter of 2018, when WTI was priced 10% higher. Although the results of Gas-Weighted producers lagged, soaring third-quarter natural gas prices suggest a catch-up in the second half of the year. In today’s blog, we analyze the second-quarter results of our universe of 39 producers and preview third-quarter results.
It has been a chaotic 18 months for North American LNG and the global gas market. In a short time, international gas markets went from oppressively oversupplied balances, high storage inventories, and historically low prices for much of 2020, to reckoning with panic-inducing supply shortage, low inventories, multi-year or all-time high prices in the biggest LNG-consuming regions. The resulting whiplash has transformed key aspects of the LNG market, including making a profound impact on the way existing LNG terminals operate, how projects secure funding and capacity commitments, and what offtakers expect for the next generation of LNG capacity buildout. The tight market appears to have settled the question of whether more export capacity is needed, at least for now, but the market’s sharp U-turn has also put potential offtakers on edge and underscored the need for contractual flexibility. Additionally, pressure to reduce greenhouse gas (GHG) emissions is higher than ever, and LNG offtakers are increasingly demanding greener solutions to address government regulations and public concerns. This convergence of factors has put the LNG market at a crossroads. Taking all of the lessons learned from the past 18 months and before, the industry must now forge a new path forward. Today, we discuss highlights from our new Drill Down report, looking at the major trends that will define the North American LNG market in the coming years.
It will still be a few years until Canada joins the ranks of nations exporting natural gas in the form of LNG. Until then, a great deal of work has to be completed on both the LNG Canada liquefaction and export facility in Kitimat, BC, and the primary gas pipeline linked to it: the Coastal GasLink. Unlike most LNG export sites in the U.S., which can receive feedgas from multiple production basins via an array of major trunklines, the LNG Canada plant will be relying on gas supplies from primarily one basin: the Montney in Western Canada. And all that feedgas will be transported across British Columbia through one mammoth pipeline. In today’s blog, we take a closer look at the small number of pipelines that will supply gas from the Montney to Coastal GasLink for eventual delivery to LNG Canada.
When fully loaded, a Very Large Crude Carrier (VLCC) sits so low in the water that it almost resembles an alligator swimming along the surface of a lagoon. Bearing the weight of 2 MMbbl of crude oil, plus ballast, fuel, crew, and provisions — not to mention the ship itself — two-thirds of an oil-laden VLCC is literally out of sight. You could say the same about the development of crude export terminal projects along the Gulf Coast: not much to see, maybe, especially during the disturbingly enduring COVID-19 era, but a lot is happening under the surface. In today’s blog, we discuss the status of onshore and offshore projects aimed at streamlining the shipment of U.S. crude oil to overseas buyers.
Global natural gas and LNG prices have spent the summer going from high to higher to the highest on record. The major European indices hit post-2008, and then all-time highs multiple times throughout the summer — even surpassing Asian prices on a handful of days. At the same time, Asian prices have set all-time seasonal records and are now sitting just below the previous single-day high settle from this past January. Usually, as the weather cools heading into fall, so do prices, but that’s unlikely this year as the European gas storage inventory is at the lowest level for this time of year than we’ve seen in recent history, and the time to replenish stocks for the winter is rapidly running out. The incredible bull run for global gas prices has been underpinned by high demand for LNG and the cascading effect of a supply squeeze in Europe, brought on by the triple threat of low domestic production, decreased imports from Russia, and a scarcity of incremental LNG cargoes. Not only is this driving record-high gas prices and increased volatility now, but the low inventory means sustained high prices for the heating season ahead. In today’s blog, we take a look at recent global gas price trends and the precarious European storage situation ahead of what is shaping up to be an incredibly bullish winter.
The natural gas futures contract for the prompt month barreled a net ~$1.00 (26%) higher in the past 12 days as the potential for prolonged production shut-ins in the Gulf of Mexico after Hurricane Ida amplified already-heightened supply fears in both the U.S. and international gas markets. The blistering price action sent the CME/NYMEX Henry Hub October futures contract soaring on Wednesday to an intraday high above $5/MMBtu and a settle of $4.914/MMBtu, the highest during September trading since 2008, while the prompt December and January contracts settled above $5/MMBtu for the first time in years. Prices at European and Asian gas/LNG hubs have similarly rallied this summer to multi-year or even all-time highs. Offshore Gulf gas production has since begun to recover, slowly, after the Ida-damaged Port Fourchon in Louisiana, the base of offshore oil and gas operations, reopened over the Labor Day weekend, but the bulk of it remains offline as power outages and other operational challenges persist. The shut-ins are exacerbating an already tight market, marked by record LNG exports, lackadaisical production growth, and a growing inventory deficit compared with year-ago and five-year average levels. Those underlying fundamentals will remain a trigger point for price spikes well after Ida-related shut-ins recover. Today, we discuss where the gas market stands heading into the final months of the injection season and the implications for winter gas pricing.
In the three years since Moda Midstream acquired Occidental Petroleum’s marine terminal in Ingleside, TX, the company has developed millions of barrels of additional storage capacity, connected the facility to a slew of Permian-to-Corpus Christi pipelines, and increased the terminal’s ability to quickly and efficiently load crude onto the super-size Suezmaxes and VLCCs that many international shippers favor. Moda’s fast-paced efforts have paid off big-time, first by making its Ingleside facility by far the #1 exporter of U.S. crude oil and now with a $3 billion agreement to sell the terminal and related pipeline and storage assets to Enbridge. The transaction, which is scheduled to close by the end of this year, will make Enbridge — already the co-owner of the Seaway Freeport and Seaway Texas City terminals up the coast — the top dog in Gulf Coast crude exports. Today, we discuss the Moda agreement and how it advances Enbridge’s broader Gulf Coast export strategy.
Many U.S. hydrocarbon production basins have experienced major ups and downs the past few years — the Haynesville, Eagle Ford, Bakken, and SCOOP/STACK, to name just a few. The Permian hasn’t been entirely immune from bad times either — crude oil and associated gas production there plummeted in the early days of the COVID-19 pandemic last year and again during the Deep Freeze in February this year — but it would be fair to say that the play’s Midland Basin has been among the energy industry’s surest bets during the Shale Era, with strong, highly predictable gains in output that producers and midstreamers alike can pretty much bank on. As a result, a number of gas-and-NGL-focused midstream companies have been taking the long view in their planning for new gathering systems, gas processing plants, and connections to a multitude of takeaway pipelines. In today’s blog, we discuss one company’s development of a now-massive and flexible hub-and-spokes network in the heart of the Midland.
The seven years since the heady days of $100/bbl oil in mid-2014 have been a tumultuous time for midstream companies tasked with funding a massive infrastructure build-out to support surging crude oil and natural gas production. Midstreamers have been buffeted by volatile commodity prices, waves of E&P bankruptcies, rapidly shifting investor sentiment, and, finally, a global pandemic. Perhaps no company has had a more challenging road than master limited partnership (MLP) Plains All American, which had to cut unitholder distributions three times over a turbulent five years as it built out a crude gathering and long-haul transportation portfolio focused on the Permian Basin. With its capital program winding down, commodity prices rising, and a new joint venture in the works, can Plains performance rebound and win back investor support? In today’s blog, we discuss highlights from our new Spotlight report on Plains, which lays out how the company arrived at this juncture and how well-positioned it is to benefit from the significant recovery in commodity prices and Permian E&P activity.
The U.S. West Coast natural gas market is at the forefront of the energy transition, but regional natural gas prices are instead signaling the need for construction of newbuild gas pipeline capacity to the region. Without it, markets west of the Permian Basin have been hard-pressed to take advantage of the supply growth in West Texas and have struggled to consistently maintain adequate natural gas supplies for some time now. To make matters worse, last month, a segment of El Paso Natural Gas Pipeline (EPNG), a primary artery for moving Permian gas west, experienced a rupture, further tightening supplies. Today, we highlight the major market impacts and longer-term implications of the pipeline blast and subsequent flow restrictions.
