Mexico’s state-owned Petróleos Mexicanos, the second-largest exporter of crude oil to the U.S. after Canada, said in late December that it will slash its export volumes in 2022 and eliminate them completely in 2023. The plan is premised on Pemex’s expectation that, with increased utilization of the company’s six existing refineries and the impending start-up of a new one, it will need every barrel of the Maya, Isthmus, Olmeca, and other varieties of oil it produces. While at first glance it may seem that Mexico phasing out exports of crude would pose a major challenge to some U.S. refineries, there’s good reason to believe that in reality it won’t. In fact, as we discuss in today’s RBN blog, there may be less to Pemex’s planned export phase-out than meets the eye.
In the aftermath of the massive Winter Storm Uri in February of last year and its impact on the natural gas industry, there has been a blizzard of civil and regulatory litigation. Whether it’s someone not providing contracted gas supply, not taking expensive must-take gas supply, or saying “not that contract, but this contract” where there was a big difference in pricing between the two, lawyers are having a field day with the meaning of two words: force majeure. To what extent was one party to an agreement protected from being in breach of contract because their deal said some things could be force majeure, or beyond their control? The purchase and sale of natural gas at issue in these contracts is overwhelmingly done through a standard base contract produced by the North American Energy Standards Board, or NAESB (pronounced “Nays-be,” not “Nazz-be”). In today’s RBN blog, we discuss the standard contract used for the vast majority of natural gas supply deals in the U.S. and how its provisions relate to the issues raised by last February’s Deep Freeze.
Pandemic. Deep freeze. Decarbonization. Stymied production growth. Sky-high prices. 2021 was definitely one for the record books. But thank goodness we made it and can look forward to a New Year! That means it is time for our annual Top 10 Energy Prognostications, the long-standing RBN tradition where we consider what’s coming next to energy markets. Say what? Surely it would be foolhardy to make predictions now. After all, we’re in the midst of a chaotic energy transition, a pandemic that’s becoming endemic, and political shenanigans in Washington and across the globe. Foolhardy? Nah. All we need to do is stick out our collective RBN necks one more time, peer into our crystal ball, and see what 2022 has in store for us.
Finally! It’s the last day of 2021, which means it’s time for our annual Top 10 Energy Prognostications blog, the long-standing RBN tradition where we look into our crystal ball to see what the upcoming year has in store for energy markets. And unlike many forecasters, we also look into the rear-view mirror to see how we did with last year’s predictions. That’s right! We actually check our work! And that’s what we’ll do in today’s scorecard blog. Then on Monday we’ll lay out what we see as the most important developments of the year ahead. But today it’s time to look back. Back to what we posted on January 2, 2021.
How do you sum up a year like 2021? It was good times for the economic health of producers and midstreamers alike. Prices were up, as were production and flows. But 2021 also brought along more than its share of chaos, including disruptive market events like Winter Storm Uri’s deep freeze and Europe’s natural gas crisis, along with general perplexity around all things clean, green, renewable, and certified. At RBN we take a different approach to assessing common industry themes. Namely, we examine the events and trends that the market considers the most important — crowd-sourced market intelligence, if you will. We can do that because every weekday we post a blog covering a single topic and blast it to almost 35,000 people, and we scrupulously monitor the website hit rate to see which blogs garner the most interest. Then, at the end of the year, we look back to see which topics rank at the top of the hit parade. That score reveals a lot about major market trends. So today we dive into our Top 10 blogs based on the number of rbnenergy.com website hits over the past year to see what we can learn about where things stand today and what’s up next.
Countries around the world are formulating and refining their strategies to reduce greenhouse gas emissions. Their policies target numerous areas such as stationary emissions, electricity production, and transportation. Within the transportation sector, one aspect that has spurred quite a bit of investment relates to reducing the carbon intensity of transportation fuels. The low-carbon fuel policies that are in place today, coupled with those being evaluated for the future, have the potential to incentivize the development of a wide range of “greener” alternatives to petroleum-based fuels in the regions where they are adopted. In today’s RBN blog, we discuss highlights from Part 2 of our Drill Down report on low-carbon fuels, focusing this time on ethanol, biodiesel, sustainable aviation fuel, and hydrogen, and the government policies that help support them.
Among the 21 countries able to liquefy methane and export LNG, Australia, Qatar, and the U.S. are the hands-down leaders, holding more than half the world’s liquefaction capacity among them. For now, Australia holds the top position but its capacity buildout is all but complete. While a number of liquefaction projects are planned Down Under, only one has reached the final investment decision (FID) stage in 2021, and it’s relatively small. Future growth seems much more likely to come from the two other big guns. Developers in the U.S. are cautiously thawing the plans for LNG projects they put on ice in mid-2020, when global natural gas prices slumped along with economies during the early months of the COVID-19 pandemic. And in February, Qatar, which was runner-up to Australian capacity until it slipped to third place due to recent U.S. additions, took FID on the first of two supersized projects to expand its LNG capacity. In today’s RBN blog, we discuss Qatar’s expansion plans and how they relate to developments elsewhere.
You would expect the start-up of Enbridge’s Line 3 Replacement project early this fall to have eased the constraints on crude oil pipelines from Western Canada to the U.S. — and it did. You’d also expect that L3R coming online would narrow the price spread between Western Canadian Select and West Texas intermediate — but it didn’t. The latest widening of the WCS-WTI spread, one of many in recent years, is another reminder that oil price differentials can be affected by many factors other than pipeline capacity availability. In today’s RBN blog, we discuss the host of issues that affect this all-important Canadian oil price metric.
The U.S. is poised for a massive buildout in renewable diesel production capacity — a boom spurred by increasingly supportive government policies and a big push by ESG-minded refiners wanting to reduce the carbon footprint of their operations. It also hasn’t hurt that while renewable diesel is produced from used cooking oil, tallow, and other renewable feedstocks, it meets or exceeds the fuel specifications of traditional ultra-low sulfur diesel and thus is considered a “drop-in” replacement for ULSD — there’s no “blend wall” that limits its use. In the encore edition of today’s RBN blog, we discuss highlights from our recent Drill Down report, which looks at why renewable diesel is a hot topic, what we can learn from California’s Low Carbon Fuel Standards program, and how much new renewable diesel capacity is in the works.
For the next few years, New Englanders will remain heavily dependent on natural-gas-fired generation — and keep their fingers crossed regarding the availability of piped-in gas for power during periods of frigid winter weather. But the power sector in the enviro-conscious six-state region has ambitious plans to gradually ratchet down its reliance on gas and other fossil fuels and increase the role of wind, solar, and battery storage. Over time, that could help to alleviate the gas-supply risk associated with New England’s seasonally insufficient gas pipeline capacity. However, front-and-center roles for highly variable renewable energy sources could pose reliability challenges of their own. In today’s RBN blog, we discuss the evolution of the region’s electric grid and what it may mean for natural gas producers and midstreamers.
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.
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.