Be Careful What You Wish For: Alberta’s Gas Price Shift

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Alberta has spent years arguing that natural gas was undervalued because it was trapped in a basin with too few outlets. That argument was always partly right. The Alberta Energy Regulator says the average AECO-C price was only $1.45/GJ in 2024, down 47% from 2023’s global European Energy crisis prices, while its 2025 outlook raised the base-case forecast to $2.71/GJ and pointed to a narrower AECO-Henry Hub differential from 2026 onward. What Alberta wanted was escape from captive-basin pricing. What it is starting to get is not just higher prices for producers, but a higher domestic cost base for every sector that built its business model around cheap gas. That is the quiet tradeoff inside the LNG export story.

The shift is no longer theoretical. LNG Canada is operating with both trains, each at 6.5 million tons per year, with the site expected to process about 2 Bcf/d of gas when fully operational. Woodfibre is expected to start in 2027 at 0.28 Bcf/d, Cedar is expected in late 2028 at 0.39 Bcf/d, and Ksi Lisims could follow in 2029 at 1.58 Bcf/d if it proceeds, something more likely with the United States and Israel conspiring to close the Strait of Hormuz. A proposed LNG Canada Phase 2 would double the site to 3.68 Bcf/d after 2029, also more likely now. That means Alberta is not moving in one jump from local pricing to global pricing. It is moving in steps, with each export project tightening the link between Western Canadian gas and overseas LNG demand.

The most important mistake in Alberta’s public conversation has been to talk as if higher gas prices are an unqualified win. They are a win for upstream producers and provincial royalties, assuming that the government doesn’t give more royalty concessions to the industry. They are not a win for fertilizer plants, gas-heavy chemical facilities, gas-fired electricity, or households that heat with gas. Alberta’s low gas price was not just a producer problem. It was also an industrial subsidy embedded in geography and infrastructure. Once the province gets more export exposure, it keeps the benefit on one side of the ledger and gives up part of it on the other. That is the core of the be-careful-what-you-wish-for theme.

The price path over the next five years is unlikely to look like a one-time crisis spike. It is more likely to look like a ratchet. A conservative anchor is the AER base case, which moves AECO-C from $2.71/GJ in 2025 toward $4.37/GJ by 2034. On top of that, LNG Canada is already operating, Woodfibre is close enough to matter to forward expectations, Cedar is now part of the late-2028 picture, and the global LNG market has become more fragile. Alberta is likely to spend most of 2026 and 2027 in a roughly $3 to $4/GJ world, move into a $4 to $5/GJ world in 2028 and 2029 as Woodfibre and Cedar come into service, and sit in a roughly $4.5 to $6/GJ world by 2030 if the global LNG market remains tight and late-decade projects continue to advance. That is still cheap gas by global standards. It is not cheap by the standards of Alberta’s recent industrial history.

Put against the recent reference point, that change is large. Alberta in 2024 was living in a $1.45/GJ gas world. A move to $3.50/GJ means the commodity price has risen 141%. A move to $4.50/GJ means it has risen 210%. A move to $5.50/GJ means it has risen 279%. That is the right frame for industrial planning. Most of Alberta’s gas users did not build their cost structures around $5.50/GJ gas. They built them around years in which AECO regularly looked depressed relative to Henry Hub and dramatically discounted relative to LNG-linked markets. Even if Alberta never converges to Asian LNG pricing, moving from a structurally discounted basin to a structurally tighter one changes capital allocation, plant economics, and competitive positioning.

Nowhere is that more obvious than ammonia and fertilizer. Best available natural gas-based ammonia production consumes about 32 GJ of natural gas per ton of ammonia. At Alberta’s 2024 gas price of $1.45/GJ, the gas component of that ammonia is about $46 per ton. In a $3.50/GJ gas world, it becomes about $112 per ton. In a $4.50/GJ world, it becomes about $144 per ton. In a $5.50/GJ world, it becomes about $176 per ton. Alberta is home to six of Canada’s nine nitrogen fertilizer facilities, so this is not a side issue. Between 2024 and a likely 2028 to 2030 pricing band, Alberta fertilizer producers are looking at gas-cost increases of roughly $98 to $130 per ton of ammonia. That does not automatically make them uncompetitive, but it does eat into the advantage that very cheap Prairie gas used to provide. A typical natural gas–based ammonia plant in Alberta produces ammonia at roughly $250 to $400 per ton depending largely on gas prices, while market selling prices have historically ranged from about $400 to $800 per ton, meaning that a move from $1.45/GJ gas toward $4 to $6/GJ can compress margins by $100 to $200 per ton if sale prices do not rise in step.

For farmers, the impact shows up directly through nitrogen fertilizer costs. Typical Prairie application rates for wheat and canola are on the order of 80 to 150 kg of nitrogen per hectare, which corresponds to roughly 100 to 180 kg of ammonia equivalent. A $100 to $150 per ton increase in ammonia production cost translates into about $10 to $25 per hectare in higher fertilizer costs, depending on crop and application rate. For large operations farming thousands of hectares, that quickly becomes tens of thousands of dollars in additional annual input costs, tightening margins unless crop prices rise in parallel.

Chemicals are more varied, but the story points the same way. The industrial chemicals segment is concentrated in Ontario, Alberta, and Quebec, with Alberta accounting for a large share of production. For methane-heavy products like methanol, hydrogen, and other syngas-derived intermediates, gas is both feedstock and fuel. Using methanol as a proxy at roughly 30 to 37 GJ of gas per ton of product, Alberta’s gas input cost would move from roughly $44 to $54 per ton at 2024 prices to roughly $105 to $130 at $3.50/GJ, $135 to $167 at $4.50/GJ, and $165 to $204 at $5.50/GJ. The exact number depends on the process, but the direction does not. A chemical sector that has sold itself partly on low feedstock cost loses part of that edge as LNG exports tighten the basin.

Historically, methanol prices in North America have often sat in the roughly $300 to $500 per ton range in stable periods, with spikes above $600 during tighter markets, which meant Alberta producers operating with sub-$2/GJ gas enjoyed a clear cost advantage on feedstock. As gas moves toward $3.50 to $5.50/GJ, the gas input alone rises into the $105 to $204 per ton range, materially increasing total production costs and narrowing margins unless methanol prices rise in parallel. That shift affects not just methanol producers, but downstream users including formaldehyde resins, plastics, paints, and fuels, where higher methanol costs ripple through into manufacturing, construction materials, and chemical supply chains.

The electricity system is the other obvious Alberta vulnerability. Gas-fired generation accounted for 76.8% of Alberta’s total generation in 2025. A reasonable heat rate for efficient combined-cycle plants is about 7.5 GJ/MWh. At $1.45/GJ gas, the fuel component of those plants is around $11/MWh. At $3.50/GJ it is about $26/MWh. At $4.50/GJ it is about $34/MWh. At $5.50/GJ it is about $41/MWh. Using Alberta’s current generation mix, the move from 2024 gas prices to a $4.50/GJ world implies an average system energy-cost uplift of roughly $18/MWh. The move to $5.50/GJ implies closer to $23/MWh. Alberta’s average pool price in 2025 was $43.68/MWh. Adding $18 to $23/MWh to the energy component is material.

That does not mean residential power bills explode. A typical Alberta household uses about 600 kWh per month, or 7,200 kWh per year. Multiply 7.2 MWh by an $18/MWh uplift and the result is about $130 per year. Multiply it by a $23/MWh uplift and the result is about $166 per year. That is on the energy side of the bill, not the full delivered bill. Delivery charges remain large and do not move one-for-one with gas. The default Rate of Last Resort is also fixed through the end of 2026, which delays pass-through for many customers. But once those protections roll forward, Alberta households will see that gas export success reaches them twice, first in their gas-heating bill and second in the power market that still runs mostly on gas.

The household gas-heating effect is larger than the household electricity effect. A typical Alberta home using about 120 GJ of gas per year would have paid about $174 for the commodity at 2024 AECO-C levels. In a $3.50/GJ world, that becomes about $420. In a $4.50/GJ world, it becomes about $540. In a $5.50/GJ world, it becomes about $660. Delivery, storage, and distribution charges mean the commodity is not the full bill, but the shift in the commodity line alone is material. Alberta households have grown used to gas being the cheap, dependable default for space heating. It likely remains the cheaper thermal option than resistance electric heat. What changes is the scale of the advantage and the degree of confidence people can have that gas will stay structurally cheap at home while being sold at better prices abroad. The silver lining should have been that it would make them consider heat pumps, but the black cloud on that is the higher electricity prices.

This is why Alberta stands apart from the rest of Canada. Quebec, Manitoba, and Newfoundland and Labrador are largely insulated in electricity because they are hydro-heavy. Ontario is exposed, but in a more layered way because gas often sets the marginal price even though it is a smaller share of total generation. Saskatchewan is exposed because it remains thermal-heavy. Alberta is where all the channels line up at once. It is a major gas producer. It has a fertilizer and chemical base that relies on low gas cost. It has a power system that is mostly gas-fired. And it has households that often heat with gas. The province is both the beneficiary and the customer of its own commodity.

There are “upsides.” Higher gas prices improve producer netbacks. They support drilling. They improve the economics of gathering, processing, and export infrastructure. They may also produce higher royalties and more investment in upstream activity. If Alberta had no domestic gas-consuming industry and a hydroelectric power system, the policy case for more export linkage would look cleaner. But that is not Alberta. Alberta has spent decades building an economy in which cheap gas was both export commodity and industrial input. Once LNG exports push it toward a more internationally linked price, those two roles come into conflict. The upstream producer and the fertilizer plant do not sit on the same side of the transaction. Neither do the gas generator and the residential consumer.

The steel story in central Canada offers a preview of how this plays out elsewhere. A modern DRI facility using natural gas alongside an EAF route still carries meaningful gas exposure. A province that is moving more steelmaking toward gas-based DRI can live with that comfortably in a low-gas world and less comfortably in a higher-gas one. Alberta should read that as a warning about path dependency. It is one thing to build a power system, industrial cluster, and heating system around cheap gas. It is another to discover midway through the asset life that the cheap-gas assumption was contingent on not succeeding too well at exporting the fuel.

The province should stop talking as if export access creates only winners. A serious Alberta strategy would acknowledge that the next five years are likely to move the province from the $1.45/GJ world of 2024 to something more like $3 to $4/GJ in the near term, $4 to $5/GJ as Woodfibre and Cedar come on, and possibly $4.5 to $6/GJ by 2030 if later projects and global tightness reinforce one another. In that world, Alberta’s industrial strategy cannot assume cheap domestic gas as a permanent fact. Fertilizer, chemicals, and power all have to be planned against a higher floor. The province does not need to panic. It does need to update its assumptions.]

The impacts on farmers, businesses and residents should be understood and adjusted for. If Alberta were rationally governed, it would be reducing its electricity system’s dependency on gas by building renewables that lower electricity prices rapidly, and reducing residential dependency on gas by transitioning to heat pumps. Gas pump prices are rising too due to the war on Iran, something that Albertans could be more buffered against with a renewables heavy grid and EVs. But Alberta is ideologically opposed to being rational and working for the good of its citizens, instead attacking renewables and pushing hard on things which benefit its oil and gas industry. The chickens will be coming home to roost over the coming years.

Alberta is unlikely to see widespread plant closures, but it is likely to lose some of its historical competitive edge. As gas prices move from the $1.45/GJ range toward $3 to $6/GJ, feedstock and energy costs for fertilizer, chemicals, and gas-fired power rise materially, narrowing margins and making new investment less attractive relative to jurisdictions like the U.S. Gulf Coast. The first impact is reduced expansion and fewer new projects, followed by pressure on older or less efficient facilities if higher gas prices persist. Employment effects are therefore gradual rather than abrupt, showing up as slower job growth and occasional plant-specific reductions rather than a broad wave of layoffs. Like the renewables policy impacts, it becomes another closed for business sign on Alberta’s doorstep.

That is the real lesson. Alberta wanted out of captive-basin discounting. It wanted better realized prices, stronger investment, and a route to global demand. It is getting part of that future now. But the old Alberta model rested on a contradiction. It assumed the province could sell gas as a globally valuable commodity while continuing to enjoy it as a locally discounted industrial input. That bargain weakens with every new LNG train on the B.C. coast and the Texas coast. Success in gas exports does not only lift producers. It rewrites the economics of fertilizer, chemicals, electricity, and home heating inside Alberta itself. That is not necessarily a reason to reject the export strategy. It is a reason to understand the bill that comes with it and to find sensible ways to mitigate it. That won’t happen under the current government.