Alberta’s grid queue is full. Your gas is not in it.

Almost everything written about connecting a large load to Alberta's grid is written for someone building a data centre. Queue position, transmission service, how many megawatts the system can carry before it stops being reliable. If what you own is solution gas being flared or vented at a battery, none of that is a constraint on you.

That is worth being precise about, because the precision is where the advantage sits. It is not that a gas owner is near the front of the queue. It is that the queue measures something a gas owner never asked for.

What the cap actually rations

On 4 June 2025 the AESO announced an interim approach to large load connections, setting a 1,200 MW interim limit through 2028 — in the release's own words, "the maximum additional large load capacity that the grid can serve without negatively impacting grid reliability". The same release states that the interim approach "applies to load projects equal or greater than 75 MW".

In the AESO's Phase I update dated September 2025, 15 projects from five developers totalling 4,800 MW qualified, and 1,200 MW across three projects from two developers was assigned. That document, published in September 2025, records load contracts as already issued for the assigned megawatts and pending execution, with the contract execution deadline extended from 4 August to October 2025.

The AESO large load projects page, read on 24 August 2026, states that all 1,200 MW of the interim connection limit was allocated: 970 MW to P2936 GLDC Load and 230 MW to P3083 Keephills Data Centre Phase I.

Against that, the same September 2025 update reports over 20,000 MW of data centre load on the AESO project list, and says in as many words that "data centres continue to request load service without matching generation".

Now read what the cap is denominated in. It is a ceiling on load the transmission system can serve, and it bites at 75 MW and up. It is not a ceiling on gas, land, gensets, containers or electricians.

Why a gas owner is not in the line

Alberta put the same threshold into regulation. The Data Centre Regulation, AR 117/2026, filed 9 June 2026, defines a large data centre as a transmission-connected load facility requesting 75 MW or more of Demand Transmission Service, as summarised on 30 June 2026.

A separate instrument narrows the scope further, and it is worth keeping the two apart. The same summary describes the large load integration process proposed by the AESO as covering data centre and industrial load but not applying to energy storage, distribution load or distribution-connected load. That is a proposed process, not enacted regulation, so it is not something to build a position on.

Two things have to be true before the enacted threshold reaches a project: it is connected to the transmission system, and it wants 75 MW or more of transmission service. A container bank on a lease, burning gas that has no line to take it, is neither.

And at the moment there is nothing to join anyway

The replacement pathway is "bring your own generation". The AESO published a proposed BYOG process on 26 June 2026, closed written feedback on 13 July 2026, and posted consolidated feedback on 15 July 2026. Legal commentary dated 9 July 2026 expected the final process published and intake open in late July or early August 2026, running roughly six-week intakes about every nine months, with connection studies of three to six months after that.

Checked on 24 August 2026, the AESO Engage page for Phase 2A still shows 15 July 2026 as its most recent update, the most recent process document is still the proposed one, and no intake window has opened.

So a grid-connected project's next entry point is an intake that does not yet exist. A load that brings its own fuel has no entry point to wait for. That gap is real, it is current, and it is the whole of the timing argument.

What being off the transmission system does not get you

This is the part that gets skipped, and it is where projects die.

• AUC approval is still required. Directive 060 says it in the AER's own words at section 4.5: "Approval for the construction and operation of electrical power plants is held by the Alberta Utilities Commission as specified in section 11 of the Hydro and Electric Energy Act."
• The own-use exemption is gone. The AUC eliminated the exemption from filing for own-use power plants in Bulletin 2022-04, issued 24 March 2022, with the amended rule effective 25 April 2022. Anyone quoting the pre-2022 position is quoting something that has not been true for four years.
• Rule 007, as amended effective 28 March 2024, sets the tiers. Under 1 MW may proceed without filing if the Hydro and Electric Energy Regulation conditions are met. From 1 MW to under 10 MW requires a checklist application "regardless of whether the energy generated is solely for its own use or for export to the Alberta Interconnected Electric System", decided within five business days of a properly completed filing. At 10 MW and above the checklist route is not available at all.
• Above 1 MW at peak load there is a second approval. Directive 060 section 4.5 states that power plants over one megawatt at peak load also require approval issued by AEPA under EPEA.
• The AUC enforces this. Green Block Mining Corp, formerly Link Global Technologies, settled with the AUC in December 2023 over three unapproved power plants, paying $346,500 plus up to $60,000 in enforcement costs and agreeing never to operate in Alberta again.

Off the grid is not off the regulator. It is a different regulator with a shorter form.

Directive 060 already makes you answer a version of this

The current edition of Directive 060 was released and effective 27 March 2026, replacing the 19 June 2025 edition. If you are flaring or venting at scale, its arithmetic is already sitting in your files:

1. Section 4.1 requires conservation where combined flare and vent gas exceeds 900 m3/day per site and the decision tree and economic evaluation return an NPV greater than Cdn$55,000.
2. Section 4.6 requires you to update the conservation economics every 12 months for any non-conserving site over 900 m3/day, keep it on file, and produce it to the AER within five working days of a request.
3. Section 4.5 names power generation as a means of conserving solution gas, and section 4.6 lists it alongside pipeline to sales, fuel and pressure maintenance as an acceptable method.
4. Section 4.4 requires operators within three kilometres of each other to evaluate clustering when they run those economics.

Then read section 4.6.1, item 5. Price forecasts for power generation projects must use the most recent 12-month rolling average of the AESO pool monthly summary price, escalated at the long-term inflation rate — or, alternatively, the cost of the power displaced at the site.

Those are the two permitted price bases. What a buyer standing on your pad would pay for the same gas is not one of them. That is not a loophole and it is not advice to file anything differently; it is a reason to know what price your own conservation file assumed before you conclude the gas is uneconomic to do anything with.

Where this argument is weak

Not being in a queue removes a constraint. It does not create a project.

Four honest qualifications.

• Volume and duration still decide everything. Directive 060's 900 m3/day and Cdn$55,000 are the thresholds at which the regulator starts caring. They are nowhere near the thresholds at which a load pays for itself. Declining solution gas on a battery with three years left is a different asset from a gathering-constrained development with a decade of it.
• The approval attaches to the power plant, not to the gas. Somebody has to hold it. If a third party owns the load and you own the gas, who owns the generation and whose name is on the AUC filing is a structuring question that has to be settled before anyone orders an engine — and it determines who is exposed if the thing gets shut down.
• No wire cuts both ways. The absence of a transmission connection is exactly why you are not rationed, and it is also why the load on your pad is your only offtake. There is no pool to sell into if the counterparty stops paying, and no grid backup if their equipment goes down. The gas goes back to the flare the day they leave. That risk should be priced into the term and the security, not waved at.
• The timing advantage expires. When the BYOG intake opens and clears, grid-served supply comes back and the relative advantage of being behind the fence narrows to the economics of the gas itself. That is a reason to move on the window, and also a reason not to build a case that depends on the window staying open.

The perishable part, dated

Everything in the AESO section of this post was checked on 24 August 2026 and it is the part most likely to be wrong by the time you read it. A final BYOG process was expected in the weeks before that date and had not appeared; it may have appeared since, and the thresholds and intake mechanics can move with it.

One sourcing note, since it matters if the number decides anything for you: the 75 MW definition in AR 117/2026 above is taken from a law firm's summary dated 30 June 2026, not from the text of the regulation. Read the instrument before you rely on the threshold.

Re-check the AESO large load projects page and the Phase 2A engagement page before you rely on any of it. Both are published and both carry dates.

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What to do with this

The useful next step is not a phone call. It is to open the Directive 060 conservation economics you are already required to keep for your non-conserving sites over 900 m3/day, and read three things: the volume it assumed, the power price it used, and the date on it. If it is more than twelve months old you owe an update anyway, and if the price basis is the pool average, the file has never been asked the question this post is about.

When it gets as far as who builds it, who holds the approval and how an owner actually gets paid — gas or power purchase, revenue share, or lease plus royalty — that is set out here, including what has to be true about a site before it is worth anyone's diligence.