Most Popular Blogs of 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.

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.

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.

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.

U.S. LNG is in the midst of a record-breaking year. Total LNG feedgas has averaged nearly 10 Bcf/d so far in 2021 and the country is on track to export somewhere around 1,000 cargoes this year, 40% more than last year. Although pipeline maintenance and flow constraints have knocked feedgas off the all-time highs seen earlier this year, feedgas and exports are likely to hit new record levels to close out the year as Sabine Pass Train 6 and Calcasieu Pass prepare to start service in early 2022. The strength in U.S. LNG export demand this year is underpinned by an incredibly bullish global gas market, which has led prices in both Europe and Asia to hit all-time highs. This has not only benefited the existing fleet of terminals, but the prolonged bullish global gas market has accelerated commercial activity for future LNG projects. Since May, more than 12 MMtpa of capacity from LNG terminals or liquefaction trains under development has been sold, pushing several prospective LNG projects closer to a final investment decision (FID). RBN covers all of the latest in our LNG Voyager Quarterly report, but in today’s blog, we take a look at some of the highlights from the report, focusing on the biggest changes in LNG development this summer.

After the crude oil price crash in the spring of 2020 and flat-at-$40/bbl oil last summer and early fall, prices for both WTI and Brent have been increasing steadily the past several months, and now stand at a kind-of-remarkable $75/bbl. This rise has been driven by a combination of demand recovery and supply restraint from both OPEC+ and U.S. producers — which begs the questions: what’s next on the supply and demand fronts, and how much more will oil prices increase from here? There’s been a lot of chatter lately that we might see $100/bbl crude prices sometime soon, and there are a lot of interested parties — many of whom don’t normally see eye-to-eye — who, for one reason or another, see their interests converge around the $100/bbl mark. The only problem is, it’s not showing up in the forward curve. Today, we look at the potential for “Benjamin-a-barrel” oil and how it might play out.

Using carbon dioxide for enhanced oil recovery offers tremendous potential for CO2 sequestration. The problem is, most the CO2 used in EOR today is produced from natural underground sources, only to be piped to EOR sites and put underground again. Realizing the full promise of CO2-for-EOR would require sourcing more and more anthropogenic CO2, or A-CO2 — in other words, “man-made” CO2 that is captured from power generation and industrial processes. In addition to the environmental benefits, there are two other drivers for making this switch from natural CO2 to A-CO2: the first is that some of the natural sources of CO2 used today for EOR are dwindling, and the second is that the push to sequester man-made CO2 is backed by tax credits and other government-backed incentives. No matter the CO2 sourcing, CO2-for-EOR requires pipelines to transport the CO2 from where it is produced to EOR sites. Today, we continue our series on the rapidly evolving CO2 market and the huge opportunities that may await those who pursue them.

U.S. LNG export terminals are running at their operationally available and contracted levels and will continue to do so, with no economically driven cargo cancellations anywhere on the horizon. Global gas prices are well supported by low storage levels in Europe, and it will take time to refill inventories, which means these high prices are not going away anytime soon. The upshot: U.S. LNG will have a very different kind of summer than it did last year, when global prices were at historic lows and many U.S. terminals saw more cargo cancellations than exports. Feedgas in April this year averaged 10.77 Bcf/d, nearly 3 Bcf/d higher than last year, and as we progress into summer, the year-on-year delta will become even more pronounced. Barring any major operational issues, feedgas demand will stay around 11 Bcf/d, which is the level needed for the terminals to produce at full capacity. That’s in stark contrast to last summer, when feedgas demand cratered and averaged as low as 3.34 Bcf/d in July as cargo cancellations peaked. Today, we look at what’s supporting global gas prices, how that impacts export economics for U.S. LNG, and what that means for feedgas demand in the months ahead.

We all hope that by the time you read this the operators of the ransomware-impacted Colonial Pipeline will have been able to restore service to more of the 5,500-mile refined products delivery system — maybe even to all of it. In any case, the shutdown of the Houston-to-New-Jersey pipeline system on Friday both exposes the vulnerability of the North American pipeline grid to malevolent hackers and reveals how, by its very nature, that same grid offers at least some degree of redundancy and resiliency built into it. A lot of that ability to respond to a crisis, whether it be a pipeline leak or a hack by an Eastern European criminal group called DarkSide, involves what you might call “market-inspired workarounds” — alternative suppliers reacting to an anticipated supply void and potentially higher prices by jumping into action. Today, we look at what the ransomware attack on the U.S.’s largest gasoline, diesel, and jet fuel transportation system can teach us.

Plains All American has an extraordinary collection of crude oil gathering systems and shuttle pipelines in the Permian Basin, as well as full or partial ownership interest in a number of long-haul takeaway pipelines to the Gulf Coast and the Cushing hub. As important as many of these individual systems and pipelines may be, it’s the interconnectivity among these assets — and especially Plains’ crude oil terminals in Midland and other West Texas locales — that gives the midstream giant’s Permian infrastructure a value far greater than the sum of its parts. Today, we’ll discuss the important role that Plains’ two terminals in Crane, TX, play in balancing the midstream company’s Permian crude oil delivery network and providing destination optionality.