Feels Like Monday -- WTI Surges -- $73.62 -- Thursday, January 2, 2025

Locator: 44588B.

Tesla: link here. Down 5% in early morning trading.

Apple: feeling competition pressure in China. Cut iPhone prices in China. This comes after the US holiday season. Shares slide 2%. Headlines suggest the world as we know it is ending.

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Back to the Bakken

WTI: $73.62. Whoo-hoo! What's up? No idea why (the sudden jump in price). Oil rallies despite large jump in fuel inventories. Over at oilprice.com. Up $1.90 today; up 2.65%.

Wells coming off confidential:

• Friday, January 3, 2025: 4 for the month, 4 for the quarter, 4 for the year,
• 40081, conf, Hess, EN-Trout-157-93-3130H-2,
• 40080, conf, Hess, EN-Trout-157-93-3130H-3,
• Thursday, January 2, 2025: 2 for the month, two for the quarter, two for the year,
• 17309, conf, BR, Washburn 44-36H,
• Wednesday, January 1, 2025: 1 for the month, one for the quarter, one for the year,
• 37665, conf, BR, Kellogg Ranch 1B MBH,

RBN Energy: two links today -- 

First: top 10 energy prognostications for 2025. 

Second: has the Trans Mountain expansion shifted western Canada's crude oil exports?

After a decade-long odyssey and a cost-per-mile that must make public-sector accountants in Ottawa wince, the Canadian government-owned Trans Mountain Expansion Project (TMX) — which nearly tripled the capacity of the original Trans Mountain Pipeline (TMP) from Alberta to the British Columbia (BC) coast — finally came into service in May 2024. As one of Canada’s most anticipated energy infrastructure projects in many years, the 590-Mb/d TMX pipeline — built alongside the long-standing 300-Mb/d TMP — was widely touted by its advocates as a surefire way to boost exports of Western Canadian crude and reduce the nation’s near-complete reliance on exporting crude oil to — and through — its primary customer, the U.S. In today’s RBN blog, we discuss some of the surprising (and not so surprising) market developments since the expansion project started.

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The RBN Energy's Top Ten Prognostications

10. Big ammonia ships will replace orders for LPG carriers.

This phenomenon is already underway, and it’s gaining steam. In 2024, orders for the workhorse vessel of international propane and butane shipments, the Very Large Gas Carrier, or VLGC, dropped like a rock. But at the same time, contracts for Very Large Ammonia Carriers (VLACs) skyrocketed to 34 new orders, expanding the VLAC orderbook to 55. We expect there will be many more VLAC orders coming in 2025, and that VLGC orders will evaporate. So what’s going on? These VLACs are not cheap, running between $120-125 million each. Is there really that much new ammonia production that needs to be shipped around the world? Hardly. Most big ammonia projects are experiencing delays or are just languishing, waiting for the right combination of subsidies and economic incentives to get them off the ground. So why the frenzy around ammonia shipping? It turns out that these new VLACs can easily flip to LPG service — so if promised big ammonia shipments are years in the future, no problem. In the meantime, they will just keep busy moving LPGs. Could that result in an overbuild of ships in LPG service? Yup, sure could. Just not in 2025.

9. Not enough new LNG capacity coming in 2025 to support the current natural gas forward curve.

In the prognostication business, there’s nothing more dangerous than predictions about forward prices, but sometimes you’ve just got to do it. The 2025 natural gas forward curve predicts a $1/MMBtu increase over 2024, from $2.40/MMBtu to $3.40/MMBtu. While this might have seemed plausible with three new LNG export facilities coming on, which is what we expected in early 2024, one delay after another has shifted the timeline. Golden Pass won’t start taking feedgas until late 2025 at best, and Plaquemines LNG, which recently shipped its first cargo, will take 18 months to ramp up fully. The one bright spot is Cheniere’s Corpus Christi Stage III expansion, with Train 1 producing its first LNG in late December (with “substantial completion” of the train to follow by the end of Q1 2025) and two more trains coming online later in the year. But add it all up and ramp actual flows based on what we’ve seen in the past, and on average over 12 months we are talking only 1.6 Bcf/d of new capacity in 2025 over 2024. That is slightly less than the nearly 1.9 Bcf/d growth in U.S. gas production we are projecting, coming primarily from the Permian and Eagle Ford. Of course, an onslaught of cold weather or a hot summer could wipe out 0.3 Bcf/d of market length in a heartbeat. But all things being equal, the odds of a $1/MMBtu increase in natural gas prices next year driven by growth in LNG exports looks pretty dicey.

8. LPG terminaling rates are high and will stay that way through 2025.

7. The Midland-to-Houston WTI price differential will justify pipeline capacity expansion.

6. No offshore SPM crude oil terminal will be sanctioned in 2025. 

We really hope to be proved wrong on this one, but it just looks like this is a case where the benefits do not justify the cost. Since 2018, numerous offshore single-point mooring (SPM) terminals have been proposed along the Gulf Coast to fully load a Very Large Crude Carrier (VLCC) without reverse lightering. Currently, only the Louisiana Offshore Oil Port (LOOP) can handle VLCCs but it is limited to two ships per month on average, far below the one per day a couple of the SPMs could manage. The remaining projects — Energy Transfer’s Blue Marlin, Sentinel Midstream’s Texas GulfLink, Phillips 66’s Bluewater Texas, and Enterprise’s Sea Port Oil Terminal (SPOT) — have faced regulatory hurdles but made progress, with SPOT receiving its U.S. Maritime Administration (MARAD) license in April. Yet none have reached a final investment decision (FID) after nearly seven years of development. The problem is shifting market dynamics. Initially, U.S. crude exports to Asia (15,000 nautical miles from the Gulf Coast) justified VLCC efficiencies, but Europe now takes 45% of exports compared to 40% to Asia, driven by demand shifts due to the Ukraine war and declining North Sea production. The shorter 5,000-nautical-mile trip to Europe diminishes the economic advantage of VLCCs, making shippers hesitant to commit to long-term capacity deals for the SPM terminals. Granted there are still good reasons for one or more of the SPMs to be sanctioned. But it is more difficult today to get shippers signed up than it originally looked, and that’s a situation that will likely get worse before it gets better.

5. There's more hype than Mcfs in the natural gas for data centers' gold rush.  

4. At least in the short term, the future of US hydrogen production is blue. 

This prognostication title is our feeble attempt at a double entendre, of sorts. Yup, the future of hydrogen is blue. From one perspective, it’s blue because blue hydrogen projects — those producing hydrogen from natural gas with emissions mitigated by carbon capture — are expected to produce far more hydrogen than green hydrogen projects, which use electrolysis powered by renewable energy. And from another perspective, the clean hydrogen outlook is blue, as in “It’s got the blues,” because progress on subsidies and tax breaks tied to hydrogen development has been painfully slow, with convoluted rulemaking casting doubt on whether the federal government’s hydrogen initiatives will happen at all. Despite blue hydrogen dominating near-term capacity projections, with about two-thirds of potential output tied to such projects, challenges loom large. The CO2 emissions from these projects must be permanently sequestered — stored forever in deep underground formations. But progress has been hampered by long permitting delays and limited project approvals. There’s also much uncertainty around the 45V tax credit for clean hydrogen, the focus of heated debate since the Inflation Reduction Act (IRA) passed in August 2022. Final rules were expected by year-end but did not materialize. And of course, who knows what will happen when President-elect Trump takes office. He has been skeptical of clean-energy initiatives in general and the IRA specifically, so 2025 looks to be a blue year for hydrogen, unless some of the big project developers succeed in lobbying for positive changes to the permitting process.

3. Ethane prices are set for a strong 2025, but key markets must align.

2. Permian natural gas prices will be back sooner than expected.  

2024 was an ugly year for natural gas prices in the Permian Basin. Pipeline capacity was maxed out, forcing producers without contractual capacity to pay to have their gas taken away, with Waha prices settling below zero 42% of the time and averaging minus $0.53/MMBtu from March to September.

The new 2.5-Bcf/d Matterhorn Express pipeline, launched in October, offered only partial relief as maintenance on other pipelines kept capacity constrained, resulting in persistently low prices through mid-November. Even after a modest recovery from late November through most of December, Waha prices dropped below $1/MMBtu in the last few days of the year. Going into 2025, with Matterhorn running at full capacity, positive prices should dominate most of the year. However, periods of pipeline maintenance are likely to create more rounds of price volatility, including occasional dips below zero.

Relief should come in 2026 with two new capacity additions: a 570-MMcf/d expansion of Kinder Morgan's Gulf Coast Express (GCX) pipeline to South Texas’s Agua Dulce hub and the 2.5-Bcf/d Blackcomb pipeline from WhiteWater and Targa, also targeting Agua Dulce.

Until then, rising associated gas production will keep the pressure on, with Permian gas output expected to hit takeaway capacity limits between December 2025 and February 2026, raising the risk of prolonged negative pricing until mid-2026 when the new capacity is operational.

1. Trump's 2025 energy goals face new industry realities.