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The Top 10 RBN Energy Prognostications - 2021 Scorecard

Thursday, 12/30/2021  RBN Energy 

https://rbnenergy.com/the-top-10-rbn-energy-prognostications-2021-s...

So here’s our 2021 Prognostications report card. Like all good New Year’s Top 10 lists, we’ll start at #10 and work our way down to #1.

1. U.S. natural gas is now totally dependent on exports to balance supply and demand. Nothing wrong with the premise on this one. Without exports, the U.S. gas market would be vastly oversupplied. But as we saw in 2021, the converse is equally true. Increasing exports, along with offshore production cuts due to Hurricane Ida, as well as only modest onshore production growth, tightened the supply/demand balance this fall. Throw in the euphoria surrounding the prospects for $100/bbl crude that permeated energy markets in October and early November and it was enough to drive natgas above $6/MMBtu for a few days, the highest price in more than a decade. The moral to the story is that high exports can also destabilize supply/demand. With more LNG export capacity coming online, linking the U.S. evermore closely to volatile global markets, that is something to worry about in the years to come.

1. Producers aren’t going to take it anymore. This one was all about producers being willing to shut in production if prices get low enough. We still believe it was an important market shift back in 2020, but with both crude oil and natural gas prices high in 2021, the concept was totally irrelevant. While we did see a number of producers limit their production growth plans, there was no pressure to cut production further. Instead, producers are stuck with the “problem” of what to do with their excess cash that has come from those high prices: give it to shareholders, pay down debt, buy a competitor, or (heaven forbid) drill for more oil and gas.

1. In crude markets, it’s all about the Permian. Granted this prediction was not exactly rocket science. As we said in our 2021 Prognostications blog, the Permian contributed the lion’s share of crude production growth from 2015 to 2019, and then during the 2020 production decline it proved to be much more resilient versus other basins. So it was in the cards that the Permian would be the big hitter in 2021, and that turned out to be true in spades. From December 2020 to December 2021, Permian crude production is up 16%, while Eagle Ford, Bakken, and Anadarko are flat to down. The only other shale basin with an increase in crude production is the Niobrara — up 7%, but off a base that’s a fraction of the Permian’s. Net-net, the Perm has been responsible for 90% of 2021 crude oil production growth. We were right on this one.

1. Midstreamers are hanging on to MVCs for dear life. 2021 turned out to be more benign for midstreamers than we were expecting. Higher prices not only float all E&P boats, they boost midstream revenues as well. Yes, there was an overbuild of crude pipeline capacity out of the Permian, along with surplus crude export capacity and still too many NGL fractionators (with more on the way). But natural gas production is ramping up in the Permian, Appalachia, and the Haynesville, all of which are going to need new pipeline takeaway capacity soon. The challenge now is getting shippers to sign up for new MVCs (minimum volume commitments) in a market where growth is no longer rewarded — what we’ve since labeled the Midstream Conundrum.

1. It’s a whole new ballgame for propane. Well, that was an understatement! Our premise a year ago was that the U.S. propane market has in effect ceded control to global markets. Case in point, the U.S. now exports more propane to Asia than the U.S. uses in its entire retail sector. The implication in our prognostication was that we expected the propane-to-crude price ratio to ramp up to its highest level since the start of the Shale Revolution. It all happened exactly as predicted. Except way too early. A feeding frenzy in September-October brought on by high exports and low inventories propelled prices above 150 c/gal and the propane-to-crude ratio to an astronomical 82%. Then the market shifted. Inventory numbers from EIA started to look like they might be OK, 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 that saw propane collapsing by 35% over a five-week period. Since then, things have calmed down, but prices remain strong, with the propane-to-crude ratio still at 60%. The price of propane is likely to remain volatile and on the high side for a good long while.  

1. Low crude prices do not mean high natural gas prices. A popular 2020 thesis asserted that low crude oil prices would depress crude-focused drilling, so crude production would fall, dragging down associated gas production with it. With gas production down, LNG exports plus winter domestic demand would push gas prices high enough to justify more drilling in dry gas basins. We begged to differ, postulating that natural gas prices would be increasing faster than crude, regardless of the absolute level of the crude oil price. Of course, crude prices did not stay low. In fact, they marched steadily higher during most of 2021, peaked in October, and slumped during the remainder of the year, ending December 37 over January. And what happened to natgas? A very similar pattern, ending the year a very healthy 47 over January. Crude and gas prices moved in tandem most of the year — meaning positively and relatively highly correlated. So based on what we learned in 2021, don’t bet on that old 2020 hypothesis. There are many more factors that go into the gas-versus-crude price relationship than a simplistic thesis can capture.

1. Ethane was left out of the 2020 NGL party, but not so in 2021. Nailed this one. Back in 2020, the prices of C3+ NGLs (propane, butanes, and natural gasoline) soared by 75% from July to December, while poor ol’ ethane languished at about 20 c/gal, up only 2% over the same period. Natural gas prices were cheap, and a lot of ethane was being rejected. We predicted party time for ethane prices in 2021, and that is just what happened, with a gain of 60% during the year, compared to only 45% for C3+ NGLs. Although petchem demand and increased exports were important factors pushing the ethane price higher, it was high natural gas prices that really did the trick, driving ethane to 45 c/gal in October. More petchem demand and higher exports are coming in 2022, so ethane has more partying ahead.

1. Houston will steal Permian crude oil flows from other markets. Well, we get half credit for this one. The premise was that the new, 1.5-MMb/d Wink-to-Webster pipeline being developed by ExxonMobil, Plains, MPLX, and others — along with Enterprise’s Midland-to-ECHO 3 pipe — would suck barrels out of other Permian outbound pipeline corridors, making Houston the dominant market for Permian crude. It turned out that in the contest for incremental production, Houston did win. Permian crude oil production was up about 600 Mb/d in 2021, and about half of the increase went to Houston. But Wink-to-Webster did not fill up, nor did capacity on Enterprise crude pipes from the Permian to the Houston market. So the Corpus Christi corridor out of the Permian retained all of its barrels and then some, and Corpus kept its title as the #1 port for U.S. crude exports. And somewhat unexpectedly, flows from Permian to Cushing also bumped up a notch during the year. But stay tuned for 2022. Next year, Houston will really be stealing flows from other markets.

1. Capital markets are greening up; hydrogen takes center stage. This time last year it was clear that Wall Street had soured on anything to do with oil and gas and a tectonic shift in capital markets was underway, with the herd rushing headlong into anything green. We concluded that if done right — and if the technology works — hydrogen would have a huge potential to transform green energy into a commodity that’s quite familiar to energy companies. (After all, it’s the hydro in hydrocarbons, without the carbon!) Now another year into our hydrogen schooling, we’ve learned that (a) it’s really expensive to make “green” hydrogen with electrolysis, and (b) it’s really expensive to capture and sequester CO₂ from “blue” hydrogen (made from natural gas), but (c) the momentum behind investments in hydrogen infrastructure keeps on building. Twelve months ago, we had three projects on our Hydrogen Billboard green project list and four on our blue project list. Now it’s 18 green projects and 15 blue projects, and many of the new projects are much larger than those first few. And there’s more. The Infrastructure Investment and Jobs Act signed by President Biden on November 15 allocates $8 billion to establish four regional hydrogen hubs. And three weeks ago, Energy Secretary Granholm requested that the National Petroleum Council prepare a major study on hydrogen technologies and markets. There are still more hydrogen incentives in the Build Back Better bill if it ever sees the light of day. These developments and many more really do put hydrogen at center stage. But being on stage does not get projects built. The next challenge is to get these initiatives and projects across the finish line.

1. 2020 was a tipping point – Risk is now a four-letter word. The notion behind this prognostication was that shale has morphed from the innovation and early adoption phase to the mature market phase, where swinging for the fences is no longer expected or tolerated. Instead, according to this premise, it’s now all about minimizing risk, keeping it between the lines, living within cash flow — and no surprises. Less hunting and more farming. More restraint in the oil-patch than we’ve seen in eras past. Yup. On the surface, that prognosis has been accurate. So this was a good one, right? Well, sort of. Because over the past year, just below the surface, there’s a lot of risk-taking going on — by private equity, through traditional hydrocarbon acquisitions and via green/renewable acquisitions. For example, most of the Permian rig count increase is coming from private-equity-backed E&Ps. But the public companies have not been standing still. Both E&Ps and midstream companies have been on the prowl for bolt-ons, investing in their core businesses through acquisitions (think Chesapeake/Vine, Earthstone/various, EQT/Alta, and Southwestern/Indigo). And public companies across the board have been planting their flag in the green/renewable space, acquiring or partnering in startups in everything from renewable natural gas and diesel to hydrogen and CO₂ sequestration. So the real story is that risk may be a four-letter word in traditional E&P and midstream investment budgets, but there is an ample appetite for risk in investment adjacencies. Expect that to be a trend that continues into 2022. 

That’s it for our review of RBN’s Prognostications for 2021, a year that turned out to be far more financially rewarding than 2020, but no less muddled as markets continue to be thrashed by the energy transition and COVID resurgences.

Now it’s time to look forward. It is still a mighty uncertain world, and the prognostications business will be just as unforgiving as it was in 2021. But we’ve polished up the ol’ crystal ball and are ready to stick our necks out one more time on Monday with our Prognostications for 2022, the Year of the Tiger. Finally! We’ve been waiting two years for the Roaring Twenties to begin in earnest.

Happy New Year!