The Top 10 RBN Energy Prognostications - 2020 Scorecard

Thursday, 12/31/2020  Published by: Rusty Braziel  rbnenergy.com

Whew. We made it! 2020 is finally in the rear-view mirror. And with the New Year, it’s time for the annual Top 10 Energy Prognostications blog, our long-standing RBN tradition where we lay out the most important developments we see for the year ahead. Unlike many forecasters, we also look back to see how we did with our predictions the previous year. That’s right! We actually check our work. Usually we roll our look back and prognostications for the upcoming year into a single blog. But after the mayhem of 2020, and considering how that upheaval has changed the landscape for 2021, this time around we are splitting our prognostications into two pieces. Monday’s blog will look into the RBN crystal ball one more time to see what 2021 has in store for energy markets. But today we look back. Back to what we posted on January 2, 2020.

Let’s get this out of the way up front. We did not forecast a global pandemic. Nor any of the maladies that came along with it. Sure, we heard about a mysterious coronavirus in Wuhan, China, a year ago, but like most everyone we assumed that it was just another isolated virus in a distant country that would soon be contained. Wrong. Very Wrong. Consequently, we did have a few significant misses in our last round of prognostications. But in the big scheme of life in 2020, we did OK.

So here’s our 2020 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. The price of natural gas has a fundamental problem. It’s crude oil. Back in 2019, 80% of the growth in natural gas production was coming from associated gas (from wells that predominantly produce crude oil), and thus insensitive to low gas prices. So an oversupply of natural gas from crude wells was hammering natural gas prices, a trend we projected would continue into 2020.  Turns out gas prices did stay low, averaging only $2.12/MMBtu for all of 2020 and sinking below $1.50/MMBtu for a few days in June. But there were a lot more things going on other than growth in associated gas that weighed down gas prices last year, including #9 just below.  
  1. Natural gas has another problem. As shale wells age, they tend to get gassier. That not only turned out to be accurate, but it was also a bigger deal than we expected. We made the case that since the gas-to-oil ratio (GOR) increases as a well gets older, and less drilling means fewer new wells (the rig count was already down by 25% in 2019), proportionally more gas would be coming from crude-focused basins. In fact, during the Spring 2020 meltdown when producers shut-in crude wells and radically cut back on drilling in crude basins, gas production did not decline nearly as much as crude — from the same wells. And in some areas where new wells were still coming on, while the crude oil decline curves look pretty typical, gas decline curves are much shallower, if not flat as a board. That’s one reason why gas production has rebounded faster and further than crude oil. More on that in Monday’s Prognostications/Part 2 blog.
  1. U.S. crude oil production winding down? Don’t think so. Well, what can we say? Crude production was still growing into 2020, regardless of the headwinds coming from lower prices and capital constraints. But then there was COVID, and all bets were off. Crude production dropped from 13.1 MMb/d in March to 11.2 MMb/d in May. Hurricanes kept volumes at about 10.5 MMb/d during the Fall before stabilizing back at the 11 MMb/d level in December. No way we saw that coming.
  1. The Permian crude to Gulf Coast differential will get crushed. This one was in the cards, COVID or no COVID. The meltdown just made it worse. We predicted that the crude oil price differential between Midland and the Gulf Coast would average a paltry $1.50/bbl, bad news for those trying to sell crude oil pipeline capacity out of the Permian. It turned out to be considerably worse. The annual 2020 average came in even lower, at $1.25/bbl — and the differential languished at only $0.70/bbl in the seven months after the meltdown. Even before COVID, Permian crude oil pipeline capacity was being overbuilt. Now, with prospects for Permian crude production growth dimmed, it looks like the overbuild will be with us for a very long time.  
  1. IMO 2020 finally arrives, not with a bang but a whimper. Remember IMO 2020? That’s the new International Maritime Organization rule that kicked in on January 1, 2020, and cut the allowable sulfur content in bunker fuel used on the open seas from 3.5% to only 0.5%. Predictions of imminent shortfalls in marine fuels and associated price spikes proliferated in 2019, asserting that neither shipowners nor refiners had adequately prepared for the transition. We predicted a whimper, and it was not even that. It was a yawner. Not only did the shipping and refinery industries do much of the needed work to prepare for the transition, about the time the new rule kicked in, so did COVID. That reduced the demand for distillate-range fuels (diesel, jet fuel), which averted any possible shortfall in supply since some of those barrels could be diverted to marine fuels. As we said in Travelin' Clean, now shipowners are taking the long view to limit greenhouse gas emissions, making significant investments in clean fuel infrastructure.  
  1. Crude oil export capacity is not a problem. As of year-end 2019, we figured there was about 6 MMb/d of crude oil export capacity along the Gulf Coast, enough to handle U.S. export needs for at least another 4-5 years. It turned out that crude exports in 2020 averaged 3.1 MMb/d, about the same as 2019, so there was more than enough growing room. Nevertheless, as we entered the new year, nine new offshore export terminal projects had been announced, each designed to allow the full loading of VLCCs without reverse lightering. Since then, most of these projects have fallen into the zombie category — not officially cancelled but nobody talks about them anymore. A couple are still alive and kicking, though. Regardless, we still believe there will be no shortage of physical export takeaway capacity, and no need for any more offshore terminals (in addition to LOOP) unless one can be built cheap enough so the economics are justified by savings on lightering costs — and that will be a challenge.
  1. NGLs are coming to the rescue in the Bakken. At the end of last year, Bakken producers were seeing the light at the end of the tunnel. Constraints on gas processing capacity and NGL pipeline takeaway capacity had plagued the basin for a couple of years. But new processing plants were coming online, and ONEOK’s new Elk Creek y-grade pipeline was starting up. NGLs were coming to the rescue! Sadly, the Bakken was whacked hard by COVID, with oil, gas, and NGL production all slashed 40% by May 2020. Since then, volumes have clawed back about half of the decline, but it will still be a while before the new infrastructure out of the Bakken enjoys anything like the utilization expected pre-meltdown.
  1. There is not enough y-grade to go around for all the new fractionators coming online.  Back in 2018, Gulf Coast fractionators hit a wall — maxing out capacity. Spot transportation and fractionation (T&F) fees from the Permian to Mont Belvieu skyrocketed to more than 70 cents/gallon (c/gal) for a few weeks. The industry responded by announcing a huge fractionator building program: 1.3 MMb/d in Mont Belvieu and another 1.0 MMb/d of new capacity in a swath of geography from Corpus Christi to Texas City. We figured that would be way more than the industry needed, and that the surplus capacity would push fractionation rates much lower than they had been before the capacity crunch. Although NGL production volumes have held up remarkably well in the COVID era, our prediction of fractionation capacity surpluses did come to pass. We figure that there is about 1.0 MMb/d of surplus capacity today, and even with several project cancellations and delays, it will be a long while before y-grade volumes catch up with fractionation capacity. That surplus has already clobbered the rates being offered for y-grade T&F. We’ve heard that one midstreamer is offering 3.75 c/gal T&F from Permian to Mont Belvieu, and another Gulf Coast fractionation offer is out there at 2.0 c/gal.
  1. U.S. LNG will get exported, even if the global gas market is glutted. Wrong, wrong, wrong.  We went against our better instincts on this one, believing what we heard from LNG market insiders — namely, that LNG was different. That volumes would continue to flow even if export economics were upside down. Violating every rule of energy fundamentals analysis. Well, now we know. LNG operates according to the same rules as everything else. If the economic pain gets bad enough, volumes stop flowing. In this case, 5.0 Bcf/d of LNG exports were cancelled for several months out of a peak of 8.0 Bcf/d pre-meltdown. Lesson learned. For what it’s worth, we did predict that the spot LNG market could get very ugly. We just didn’t forecast how ugly it could be. The good news is that LNG exports have roared back since October, hitting all-time highs in December. But we are already hearing of a new, smaller round of cancellations in the months ahead due to high shipping costs.
  1. Shale is not over, but it is going to be much more difficult to get projects done. Another correct prediction, but with the COVID-induced meltdown, an order of magnitude more brutal than what we were expecting. A year ago, the market was coming to terms that Wall Street had soured on anything to do with oil and gas, and industry players were reeling from what seemed like a continuous cycle of capacity constraints, the need for long-term capacity commitments, overbuilding, low prices, and collapsing price differentials. But today it looks a lot worse. We are trying to wrap our heads around the staggering $145 billion in E&P write-downs in the first three quarters of 2020 (WSJ 12/27/20) and the prospects of a world bent on ramping down its use of hydrocarbon fuels more quickly than we thought 12 months ago. No, shale is not over. But it’s a totally different reality out there. If project development was going to be difficult before COVID, now the prospects for most new infrastructure projects looks abysmal.   

That’s it for our review of RBN’s 2020 Prognostications — the good, the bad and the ugly. In case we forgot to mention it, on the Chinese zodiac, 2020 was the Year of the Rat. Now that seems entirely appropriate. So it’s a relief to have the 2020 s***show behind us. But when you think about it, the energy markets did reasonably well, relatively speaking. Products flowed, demand was met, and much of the market is back to where it was in early 2020, if not better.  

And now it’s time to look forward. Yes, there is a lot of uncertainty out there, and making predictions — especially about the future — is risky business (thanks Yogi!). But we’ve polished up the ole crystal ball and are ready to stick our necks out one more time on Monday with our Prognostications for 2021, Year of the Ox. So stay tuned.

And Happy New Year!

Views: 161

Reply to This

© 2021   Created by Keith Mauck (Site Publisher).   Powered by

Badges  |  Report an Issue  |  Terms of Service