2026: When Energy Markets Stop Behaving as Expected

Global Energy Outlook - Why shifting dynamics in coal, gas, and hydrogen could reshape energy economics sooner than most forecasts anticipate.

I’m writing this in January 2026, and I need to say something uncomfortable: the consensus outlook for global energy markets is probably wrong. Not because the analysis is careless—most of it is rigorous—but because it assumes continuity. And 2026 looks increasingly like the year that assumption breaks down.

Let me explain what I mean by walking through three scenarios that may sound speculative, but in reality represent the most plausible disruptions facing energy markets this year.

Scenario One: China Peaks Coal Consumption - This Quarter

Everyone knows China's 15th Five-Year Plan (2026-2030) would be formally adopted in March 2026, and authorities have committed to gradually "phase down" domestic coal use. The consensus: coal consumption peaks around 2027-2028.

But here's what happened in H2 2025 that most of us did not fully process: China's CO2 emissions have been flat or falling for 18 months. While everyone watched China add record renewable capacity (400+ GW of solar and wind in 2025), they missed the inflection point.

China's coal consumption increased by only 1.7% in 2024, down from 3.4% in 2023. But Q4 2025 data shows something extraordinary: clean energy growth has been covering all or nearly all of the rise in electricity demand in recent quarters. The marginal energy demand is now being met by renewables, not coal.

The upheaval nobody's pricing in: IF China's coal consumption peaks in Q1 2026? Not in 2028. This happens not because of policy mandates, but because renewable deployment has hit escape velocity. Chinese authorities installed 235-270 GW of solar in 2026 according to industry projections, rising to 280-340 GW by 2030 - but these are minimum projections that assume linear growth.

What this means for you:

Thermal coal exporters (Australia, Indonesia, Russia): You may find that China’s coal demand does not unwind slowly over time but instead adjusts over a much shorter period once key structural limits are reached. Projects financed assuming Chinese demand through 2030 are suddenly uneconomic by 2027.
Coking coal players: You get a brief reprieve as steel demand holds, but watch India. If China demonstrates peak coal is achievable at $13,000 GDP per capita, India accelerates its timeline by 3-5 years.
LNG developers: The "coal-to-gas switching" story in Asia just became fiction. Gas competes with ever-cheaper renewables, not expensive coal.
Renewable equipment manufacturers: You can't keep up with demand. Chinese manufacturers are already sold out through 2027. Non-Chinese manufacturers who haven't locked in silicon wafer supply and rare earth elements this quarter will miss the entire cycle.

The opportunity: China is entering a phase where grid-scale storage becomes system-critical. China needs 150+ GW of storage by 2028 to absorb renewable variability. While domestic manufacturers will supply most capacity, the technical standards and commercial structures being established now will define who captures long-term value.

Scenario Two: NEOM Green Hydrogen Becomes Operational—And Breaks Everything

2026 may be the year green hydrogen stops being a policy aspiration and begins to function as a bankable industrial input—at least in one geography.

Saudi Arabia’s NEOM Green Hydrogen Project is now more than 80% complete, with approximately 4 GW of dedicated renewable capacity scheduled to come online by mid-2026. The project targets 600 tonnes per day of hydrogen production, equivalent to roughly 219,000 tonnes annually, positioning it as the largest single green hydrogen facility ever attempted.

Current project timelines indicate initial ammonia exports beginning in late 2026, earlier than originally anticipated. While modest in global volumetric terms, the significance lies in scale and integration: NEOM combines utility-scale solar and wind, electrolyzers, storage, and export infrastructure within a single, sovereign-backed system.

Cost structures matter. Publicly available data suggest delivered renewable power costs in the range of $15–20/MWh, with electrolyzer capex secured during the 2023–2024 downturn. Under these conditions, modeled green ammonia production costs approach $400–500 per tonne, placing them within reach of grey ammonia pricing in high-gas-price environments and materially below most green hydrogen benchmarks to date.

The importance of this development is not that green hydrogen suddenly becomes cheap everywhere. It is that, for the first time, a large-scale project demonstrates commercial viability without relying on perpetual subsidies. That distinction - between theoretical feasibility and bankable execution - is what marks a structural shift.

If NEOM performs as designed, it establishes a reference point for future hydrogen projects globally. It does not signal immediate market transformation, but it does reset expectations about what is technically and financially achievable within this decade.

How? Three factors nobody modeled correctly:

Desert solar is cheaper than anyone forecasted: Saudi Arabia has developed mega solar projects at record low prices, with a highly ambitious target to achieve 50 percent renewable adoption by 2030. The actual installed costs for NEOM solar came in 20% below projections.
Electrolyzer costs collapsed faster than the learning curve predicted: Chinese manufacturers flooded the market with sub-$400/kW systems in 2025. Saudi Arabia bought in bulk.
Vertical integration works: Saudi Aramco controls the entire value chain - renewable power, electrolysis, ammonia synthesis, shipping. No intermediary margins.

What this means for you:

European hydrogen projects: You’re targeting green hydrogen production costs of $5–6/kg even after subsidies - but NEOM is already operating on a different economic plane. With ultra-low-cost power, integrated infrastructure, and sovereign backing, the project is on track to deliver green ammonia at roughly $4/kg hydrogen-equivalent - without ongoing subsidies. This isn’t a technology breakthrough so much as a system advantage: generation, electrolysis, and export are built as one. What remains aspirational elsewhere is already bankable in Saudi Arabia, and that gap - not headline costs - is what reshapes the hydrogen market.
Australian hydrogen export ambitions: You're competing with a country that has unlimited capital, half your labor costs, and zero political opposition to mega-projects. The "hydrogen superpower" narrative just shifted from Australia to the Middle East.
Ammonia/fertilizer producers: Chinese and Indian buyers can now source green ammonia cheaper than grey. The global ammonia market - $70 billion annually - just got disrupted. If you're not renegotiating long-term contracts now, you're about to lose customers.
Shipping companies: Green ammonia as marine fuel just became viable. Not in 2030, but in 2027. The first ammonia-powered bulk carriers are being retrofitted right now.

The opportunity: The architecture underpinning NEOM is designed for replication. If early performance benchmarks are met, Saudi Arabia is positioned to roll out multiple projects of comparable scale, creating a multi-tens-of-billions-dollar EPC pipeline. For firms able to mobilize at speed, the window to establish leadership could open quickly - and close just as fast.

Scenario Three: A Russian-Ukrainian Infrastructure Ceasefire Creates European Gas Chaos

Everyone's modeling the Russia-Ukraine conflict as "continued grinding stalemate" or "negotiated ceasefire with territorial concessions." Nobody's modeling the scenario that's actually most likely: a limited infrastructure ceasefire brokered by Trump in Q2 2026.

Here's what happens: Russia and Ukraine agree to stop targeting each other's energy infrastructure - pipelines, refineries, power plants, storage facilities. Not because they've made peace, but because Trump makes it clear U.S. security assistance depends on it.

This sounds stabilizing. It's not. It's the biggest energy market upheaval since 2022.

Here's why: TurkStream remains the only operational route for Russian gas to flow into Europe, with Turkey purchasing around 20 bcm per annum and serving as a critical transit route for sales to the Balkans, Hungary and Slovakia. Europe currently imports about 15 bcm/year of Russian gas - down from 150+ bcm pre-war.

The infrastructure ceasefire doesn't restore Nord Stream (destroyed) or restart the Ukraine transit system (politically impossible). But it does stop the attacks that have been driving insurance costs through the roof for any Europe-Russia energy trade.

Suddenly, the economics of importing Russian gas via TurkStream improve dramatically. The prospect of even a small jump in imports (from the current 15 to 30-40 bcm per annum) would have a major impact on a gas market that is soon to be the recipient of the long-anticipated wave of new LNG projects in 2026.

The upheaval: By late 2026, European gas prices may settle into a $6–8/MMBtu band as new U.S. LNG supply collides with a partial return of Russian volumes. For American exporters who financed projects on the assumption of $11–13/MMBtu pricing, this marks a structural reset - one that turns marginal cargoes uneconomic.

Here's the second-order effect nobody sees coming: Hungary, Slovakia, Austria, and potentially Germany start importing Russian gas again—not at 2021 levels, but enough to matter. Not because they love Russia, but because industrial competitiveness demands it. European chemical, steel, and fertilizer producers can't compete globally paying $12/MMBtu when Asian competitors pay $8/MMBtu.

What this means for you:

U.S. LNG developers: Projects that FID'd in 2023-2024 assuming sustained high European prices are underwater. European offtakers start renegotiating volumes downward. If you don't have Asian buyers locked in with price floors, you're exposed.
European renewable developers: You just got a reprieve—from the wrong source. Cheap Russian gas competes with your power generation economics, but paradoxically increases political support for accelerating the renewable transition as Europe realizes energy independence requires domestically produced power.
Pipeline infrastructure companies: Eastern European gas transit infrastructure—written off as stranded assets—suddenly has value again. But Western European terminals built for U.S. LNG face utilization problems.
Qatar Energy: You win. As U.S. LNG struggles with margin compression and Russian gas remains politically toxic, Qatar's position as reliable, cost-competitive supplier strengthens. The North Field expansion proceeds ahead of schedule.

The opportunity: Companies that can deliver grid-scale renewable power + storage in Eastern/Central Europe capture industrial offtake contracts from manufacturers desperate to hedge against Russian gas volatility. The pitch isn't "save the planet"—it's "fix your supply chain risk."

What All Three Scenarios Have in Common

None of these are "tail risks." Each has >50% probability of occurring in 2026. But conventional forecasting doesn't capture them because they're discontinuities, not trends.

Here's what they share:

1. Technology deployment is moving faster than anyone models

Chinese renewable build-out, Saudi electrolyzer cost reductions, European behind-the-meter storage - all are happening at rates that make linear projections obsolete by the time they're published.

2. Geopolitics creates opportunities, not just risks

A Russian-Ukrainian infrastructure ceasefire sounds like de-escalation. For U.S. LNG producers, it's an existential threat. For industrial gas consumers, it's salvation. For renewable developers, it's complicated. The same event creates winners and losers depending on positioning.

3. First movers capture disproportionate value

NEOM's six-month head start in green hydrogen exports isn't just timing—it shapes global price expectations and contract structures for a decade. Similarly, being first to lock in rare earth supplies or battery storage contracts before the China peak coal shock hits determines market position through 2030.

What Smart Stakeholders Do Right Now

Stop using consensus forecasts as planning assumptions. Consensus assumes continuity. 2026 delivers disruption.

Model discontinuities explicitly. Run scenarios where China peaks coal in 2026, where NEOM undercuts your hydrogen economics, where Russian gas partially returns. Stress-test your projects against not what's "most likely" but what's most disruptive.

Position for volatility, not steady-state. The energy companies that thrive in 2026 aren't those with the best long-term strategies for a 2035 net-zero world. They're those that can capitalize on 12-18 month windows when market structures break.

Build optionality into everything. Fixed-price, take-or-pay contracts look smart when markets are stable. They're suicide when the rules change. Structure deals with volume flexibility, price escalation clauses tied to real inputs, and force majeure provisions that actually protect you.

Watch second-order effects. If China peaks coal consumption, what happens to Australian export volumes? If Australia loses China volumes, where do those cargoes go? If thermal coal goes to India at distressed prices, what happens to domestic Indian producers? Three steps downstream from the initial shock is where the real money gets made or lost.

The Uncomfortable Truth

Energy transition isn't a smooth glide path from high-carbon to low-carbon. It's a series of violent adjustments as technology costs hit inflection points, as geopolitical realities shift, and as infrastructure built for one world tries to operate in another.

2026 is when several of these adjustments happen simultaneously. The companies that survive—and thrive—will be those that treated these scenarios not as interesting thought experiments but as action plans.

At EnergyStrat Consulting, we're not interested in telling clients what they want to hear about steady growth and manageable transitions. We're interested in helping them navigate the actual market that exists—which means preparing for discontinuities that sound impossible until they happen.

Because here's the final uncomfortable truth: every major energy market disruption of the past 20 years—shale revolution, renewable cost collapse, Russia-Ukraine supply shock—was dismissed as implausible right up until it wasn't.

The difference between winners and losers in 2026 won't be who had the best forecast. It'll be those who acted on scenarios that the consensus called crazy.

Are you ready to be called crazy? Because if you're not, you're probably using the wrong planning assumptions.

Let's discuss which upheavals pose the greatest risk—or opportunity—for your organization.