The Top 10 RBN Energy Prognostications – 2025 Scorecard

Well, 2025 is now in the books, allowing us time for reflection, resolution-making, and pretending we always knew how the year would turn out. For RBN, it means it’s almost time for our annual Top 10 Energy Prognostications blog, the long-standing RBN ritual where we peer into our crystal ball to see what the upcoming year has in store for energy markets. But there’s something we need to do first. 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 blog. Then on January 5 we’ll lay out our prognostications for the year ahead. But today, it’s time to look back. Back to what we posted on January 1, 2025, to see how we did in the Top 10 RBN Energy Prognostications — 2025.

So here’s our 2025 Prognostications report card. We’ll start at #10 and work our way down to #1. 

10. Here Come the Big Ammonia Ships, Replacing Orders for LPG Carriers. 

In 2024’s LPG shipping business, many new ship orders were shifting from VLGCs — the Very Large Gas Carrier workhorse of international propane and butane shipments — to VLACs, or Very Large Ammonia Carriers, because those VLACs can carry both LPG and ammonia. That hardware shift was happening even as many large ammonia projects were experiencing delays or were simply languishing, waiting (often in vain) for the right combination of subsidies and economic incentives to get off the ground. We predicted that the trend toward flexible-cargo (and flexible-fuel) vessels would continue into 2025 regardless of what happened in the ammonia market — and we got this one right. Even with much more of the bloom coming off renewable and green initiatives, and ammonia projects suffering along with everything else, roughly 85% of the 100+ vessels in the VLGC/VLAC orderbook as of year-end 2025 are flexible-cargo ships. Shipowners have continued to order VLGC/VLAC vessels on the view that the tide may someday turn, and that paying the incremental capital cost to be able to carry LPG and ammonia is worthwhile insurance — just in case.

9. Not Enough New LNG Capacity Coming in 2025 to Support the Current Natural Gas Forward Curve. 

Last year we reluctantly predicted that the roughly $1/MMBtu increase implied back then by forward natural gas prices (from $2.40/MMBtu in 2024 to an annualized $3.40/MMBtu in 2025) was “pretty dicey.” Reluctantly, because there’s nothing more dangerous than predicting forward prices in a prognostication blog — but we had good reasons for our projections. The logic was that delays in LNG facilities, especially Golden Pass, would limit the increase in LNG exports to only about 1.6 Bcf/d of new capacity in 2025 versus 2024, driven mostly by what we predicted would be a leisurely 18-month ramp of Venture Global’s Plaquemines LNG to 20 MMtpa, or about 2.7 Bcf/d. Boy, did we underestimate Venture Global! Plaquemines was already up to 2.7 Bcf/d by July and is now running at roughly 3.9 Bcf/d. Combined with Cheniere’s Corpus Christi Stage III expansion, effective U.S. LNG export capacity is up about 4.5 Bcf/d, nearly 3X since last December. Actual natural gas production was also higher than our forecasts, but not by that much. So, the market was tighter than we projected. Consequently, the annual price delta came out to be $1.20/MMBtu ($2.40/MMBtu in 2024 to $3.60/MMBtu in 2025). Let that be a lesson to us all. Don’t underestimate LNG exporters.

8. LPG Terminaling Rates Are High and Will Stay That Way Through 2025. 

We’ve got no excuses for this one. Our prediction did not happen. LPG export terminaling rates were in the dumper by April and stayed that way. Here’s the backstory. For the better part of a decade, terminal operators could charge little more than a nickel per gallon to move propane and butane (LPG) across their docks. Then in 2024 the spot rate soared from 7 c/gal in March to an astronomical 29 c/gal in September before settling at a still-elevated 15 c/gal in December. We predicted that this situation would likely be with us through most of 2025, since dock capacity would continue to be constrained. We assumed that most new NGL dock capacity coming on in 2025 would be used for ethane. Yep, LPG exports in 2025 were relatively flat, with propane up only 1.4% and total LPG (with butane) up 2.8%. But exports were curtailed more by international demand than by supply availability, and additional production mostly went into inventory (resulting in record inventory levels by the start of the winter demand season). With demand for exports essentially flat, terminal rates dropped back to a nickel per gallon by Q2 2025 and stayed there for the next six months. Only in Q4 did rates move higher, but only by a few pennies. Another lesson learned. It doesn’t take that much of a demand shift to have a big impact on terminaling rates.

7. The Midland-to-Houston WTI Price Differential Will Justify Pipeline Capacity Expansion. 

We thought it was a good bet that Permian crude production would continue growing in 2025, and it did, by around 200 Mb/d year-on-year. That meant flows would increase capacity utilization on pipes to Corpus, Houston and Beaumont — perhaps enough to increase the Midland-to-Houston (MEH) price differential from the $0.40-$0.50/bbl range in 2024 to the $0.75-$1/bbl range in 2025. It followed that if that happened, it might be enough to justify a new pipeline capacity expansion project out of the Permian. Sadly, it was not to be. The 2025 Midland-to-Houston differential mostly languished below $0.25/bbl, well below 2024. Blame weaker crude export volumes, capacity creep on egress pipelines, and a generally weaker crude oil market, but regardless of the reasons, nobody is announcing new pipeline projects at these levels.

6. No Offshore SPM Crude Oil Terminal Will Be Sanctioned in 2025. 

Last year, we predicted that there would be no decision to build a new offshore oil terminal to fully load Very Large Crude Carriers (VLCCs), the big crude ships. It just looked like a case where the benefits would not justify the cost. Lower crude export volumes for the year (down ~3.5%) certainly did not help the case. Although there were a few relevant announcements, like the Trump administration issuing a deepwater port license approval to Sentinel Midstream for its Texas GulfLink, none of the offshore single-point mooring (SPM) terminals announced any real commercial progress. We really hoped to be proved wrong on this one, but it was not to be. 

5. There’s More Hype Than Mcfs in the Natural Gas for Data Centers Gold Rush. 

Last year it certainly looked like the gas-for-data-center power-generation hype was getting way ahead of itself. We saw no way that natural gas demand for data-center power generation would see any meaningful boost in 2025 — and that’s the way it turned out. In fact, more so: Natural gas demand for power generation actually fell by a couple of percent in 2025, with primarily renewables (wind and mostly solar) displacing gas along with a little more coal used in power plants. Beyond that, even though total U.S. power consumption was up 1.6%, the increase was spread broadly across the residential, commercial and industrial sectors. Data centers did not contribute any more than homes or industrial plants to overall power-sector growth. No doubt data-center and other power consumption will accelerate in the coming years, but perhaps not by as much — or as soon — as many market forecasts suggest. See our 2026 prognostication on the topic tomorrow for more on that.

4. At Least in the Short Term, the Future of U.S. Hydrogen Production is Blue. 

This was our admittedly feeble attempt at a double entendre — “blue” as in a downbeat outlook for clean hydrogen overall, but also blue hydrogen specifically: the color code assigned to projects that produce hydrogen from natural gas with emissions mitigated through carbon capture. At the time, blue hydrogen appeared to be one of the few segments of the hydrogen market that still had some forward momentum. That call turned out to be more prescient than we expected. The push toward green hydrogen has largely collapsed. Persistent technical hurdles, unfavorable economics, the winding down of subsidies, and the demise of the Biden administration’s hydrogen hub initiative effectively signed green hydrogen’s death certificate, at least for now. In contrast, the Trump administration’s One Big Beautiful Bill Act (OBBBA) gave blue hydrogen new legs, offering fresh economic incentives for hydrogen projects paired with carbon capture. Whether those incentives will ultimately be sufficient to launch enough clean hydrogen capacity to move the needle — in the short term or the long term — remains very much an open question.

3. Ethane Prices Are Set for a Strong 2025, but Key Market Factors Must Align. 

This was another price forecast, but a fairly safe one. We could have been right in two different ways: either ethane prices rising relative to natural gas because of stronger export demand tied to new Enterprise and Energy Transfer dock capacity (what we thought would happen), or higher natural gas prices lifting ethane values through rejection economics. It turns out that the price of Mont Belvieu ethane averaged 25.3 c/gal in 2025, up 6.3 c/gal, or 33%, from 2024. But that increase was driven entirely by higher natural gas prices, as discussed in Prognostication #9. The price ratio of ethane to Henry Hub gas, on a Btu equivalence, fell from about 1.2X in 2024 to roughly 1.1X in 2025, despite the new export capacity, largely because of a weak petrochemical market, meaning the price of ethane fell relative to the price of gas. In the prognostications business, it is good to be right, even if it is for the wrong reasons.

2. Permian Negative Gas Prices Will Be Back Sooner Than Expected. 

Well, we admit it — this was a relatively easy one to see coming. Another dismal year for Permian gas. 2024 had been ugly for natural gas prices in the Permian, with Waha prices (the main Permian gas hub) settling below zero 42% of the time and averaging minus $0.53/MMBtu from March through September. Even with the new 2.5-Bcf/d Matterhorn Express pipeline coming online in late 2024, it was clear by year-end that Permian gas prices would soon be back in the doghouse. That is exactly what happened in late March 2025, when Waha averaged minus $0.30/MMBtu. In early October, Waha hit a record minus $8.79/MMBtu, meaning that some poor producer paid nearly $9/MMBtu to have someone haul his gas away. Ugh! But on the positive side of the ledger, Henry Hub gas prices were higher for the year, which provided some overall lift to Waha prices — but only up to an average of $0.75/MMBtu. Waha still traded below zero 24% of the time and averaged about $2.75/MMBtu below Henry Hub. Relief is coming in 2026, but not until the latter part of the year. More on that in Monday’s 2026 prognostications blog. 

Our scorecard for the #1 Prognostication for 2025? First, a word from your sponsor.