Pathways & the West Coast Pipeline: A Taxpayer's Assessment

Ottawa and Alberta promised a privately financed pipeline and delivered a 90-per-cent publicly owned one costing $35–44 billion, with its lone private partner declining to risk capital and no customers signed.

Alongside it, taxpayers fund the linked Pathways carbon capture project through at least six stacked mechanisms: a 50 per cent refundable federal tax credit with no upper limit — meaning cost overruns automatically enlarge the public bill — now extended five extra years; a new credit for using CO₂ to pump more oil; $3.2–5.3 billion in Alberta cash grants; a $1.2 billion carbon price guarantee; unquantified operating subsidies; and a halving of the annual carbon-standard tightening rate for the five largest emitters, which forfeits provincial revenue without appearing in any budget line.

Meanwhile the project's promised emissions reduction has fallen 77 per cent, from 68 megatonnes to 16, and its cost estimate has roughly doubled. The revenue case rests on the price differential Trans Mountain already narrowed — and by one bank's assessment that differential is now near fair value, making further narrowing unlikely.

Alberta may post a surplus this year, but only because a war closed the Strait of Hormuz and swung the books by $13 billion in 48 hours; that is precisely why deepening a revenue base already 18 per cent dependent on non-renewables, with a break-even oil price of US$74–77 against forecasts in the $50s, is the wrong lesson to draw from a lucky year. Before the binding agreements land on November 15, taxpayers are owed a single published number for what all of this costs.

The headline concern

In November 2025, Ottawa and Alberta signed a memorandum of understanding promising a new West Coast oil pipeline that would be "financed and constructed by the private sector." Eight months later, that promise is gone.

The proposal Alberta filed on July 2, 2026 has the pipeline built and owned overwhelmingly by government: the federal Crown corporation Trans Mountain Corporation and Alberta's Petroleum Marketing Commission together holding 90 per cent, with Calgary's Pembina Pipeline Corporation taking a 10 per cent economic interest — and Pembina has stated it will retain full discretion over any final investment decision and will not risk any of its own capital before making those choices.

The estimated cost: $35.2 billion to $43.7 billion, including contingencies.

Steven Guilbeault, who quit cabinet over the original MOU, put the arithmetic bluntly: taxpayers are potentially on the hook for as much as 90 per cent of that. Pembina Institute's Chris Severson-Baker was blunter still — after a year of both governments insisting they would hold out for a private proponent, Canada has "another almost 100-per-cent-funded-by-taxpayer pipeline."

Federal Energy Minister Tim Hodgson, asked how much Ottawa would be on the hook for, could not say. He offered instead: "I am quite comfortable that this is a good investment for Canadian taxpayers."

That is the central question this assessment puts to readers: comfortable on what basis, and at what documented number?

Part 1: Where the money comes from — the full stack

Public support for this package doesn't arrive as one line item. It arrives through at least eight separate channels, most of which never appear together on a single page. Several are not obvious as spending at all — which is precisely why they warrant scrutiny.

1.1 — How these mechanisms actually work

Before the numbers, the plumbing. Governments have several ways to move money to a company, and they differ enormously in how visible they are.

A tax credit is a discount on the tax bill.

An ordinary tax deduction reduces the income a company is taxed on. A tax credit is far more powerful: it comes off the tax owed, dollar for dollar. Spend $100 on qualifying equipment with a 50 per cent credit, and $50 comes straight off what you owe the government.

The federal CCUS credit is refundable — the critical detail. A non-refundable credit can only reduce your tax bill to zero. A refundable one means that if the credit exceeds what you owe, the government writes you a cheque for the difference. It is a subsidy delivered through the tax system rather than through a spending program. The money is just as real; it simply never appears as a program expenditure in the public accounts. It shows up as revenue that didn't arrive.

Why this matters politically: spending programs get debated, voted on, and reported. Tax expenditures are approved once and then run quietly for years.

"No upper limit" — what that actually means

This is the single most important structural feature in the package, and it's easy to miss.

Most government support programs are appropriated: Parliament votes a fixed pot — say $2 billion — and when the pot is empty, the program stops. The taxpayer's maximum exposure is known in advance, on the day the program is created.

The CCUS investment tax credit is not built that way. It is an entitlement: any company that meets the eligibility rules gets the credit, and there is no ceiling on the total. The Parliamentary Budget Officer flagged this explicitly — there is no upper limit to the CCUS investment tax credit as designed, meaning the public could be on the hook for more than any published estimate.

The practical consequences:

• The cost is an estimate, not a budget. Published figures are forecasts of what companies will choose to spend. They are not caps.
• Cost overruns automatically increase the public bill. If Pathways is built for $16.5 billion, taxpayers cover 50 per cent of eligible capture equipment. If it comes in at $30 billion, taxpayers cover 50 per cent of the larger number. The subsidy scales with the overrun. Nobody has to approve that increase; it happens by operation of law.
• Forecasting error runs one direction. The PBO already found Finance Canada's estimate low: Ottawa forecast $4.6 billion for 2022–28; the PBO put it at $5.7 billion — a $1 billion miss on a program still in its infancy.

Set against a project whose price tag has roughly doubled, an uncapped percentage subsidy transfers the cost-escalation risk to the public automatically and invisibly.

A grant is cash out the door.

A grant is what most people picture when they hear "subsidy": government transfers money to a company. It appears as an expenditure. There is no tax machinery involved.

A contract for difference (CfD) is a price guarantee — an insurance policy written by taxpayers.

Two parties agree on a "strike price." If the market price lands below it, the government pays the difference. If it lands above, the arrangement is neutral or the company pays back.

Here, the underlying price is the value of carbon credits. The company's worry is that it spends billions on capture equipment and then credits turn out to be worthless — so the investment never pays back. The CfD removes that worry by putting the taxpayer on the other side of the bet. The public absorbs the downside; the company keeps the operation.

The cost is unknowable in advance. It depends entirely on where carbon prices land a decade from now. That's what makes it a contingent liability — a promise that may cost nothing or may cost the full committed amount.

Foregone revenue is the invisible one.

If a government charges a company less than it otherwise would, that is money not collected. It never appears as spending because no cheque is written. But the fiscal effect on the treasury is identical to writing one.

This is where the TIER concession in the July agreement lives — and why it deserves its own explanation.

1.2 — How TIER compliance payments work

TIER — Alberta's Technology Innovation and Emissions Reduction system — is the province's industrial carbon price. Understanding it is necessary to see what was given away in July.

It does not tax every tonne. This is the most common misconception. TIER is an intensity system: each large facility (generally, those emitting 100,000+ tonnes a year) is given an emissions benchmark — an allowed amount of CO₂ per unit of production. Emit below your benchmark and you're fine. Only the tonnes above the benchmark carry a cost.

A facility over its limit has several ways to settle up:

1. Cut emissions at the site.
2. Pay into the TIER fund — buying a "fund credit" for each excess tonne at the set fund price (currently $95/tonne, frozen there since May 2025). This is the channel that puts cash in provincial hands.
3. Buy emission performance credits (EPCs) from a facility that beat its benchmark. Money moves company-to-company; the government gets nothing.
4. Buy Alberta offsets — again, company-to-company.
5. Use the Direct Investment pathway — spend on approved on-site reduction projects instead of paying.

Note that only option 2 generates public revenue. Under current rules, credits and offsets can cover up to 90 per cent of a facility's obligation — so the fund is the residual, not the main channel.

The tightening rate is the engine. Each year the benchmark gets stricter by a set percentage — the "tightening" or "stringency" rate. This is what makes the system bite over time: stand still and your obligation grows automatically. The May 2026 Implementation Agreement set that rate at 2.0 per cent annually for large oilsands facilities and specifically for firms building and operating Pathways.

What the July agreement changed: oilsands companies that hit their Pathways and emissions milestones get their required annual tightening cut from 2 per cent to 1 per cent. Alliance president Kendall Dilling confirmed this concession was essential to getting the deal done.

Halving the tightening rate halves the rate at which obligations grow. Compounded over a decade-plus across the largest emitters in the province, that is a substantial reduction in future compliance costs — some of which would have flowed into the TIER fund, and some into Alberta's carbon credit market.

The fiscal point: this is a subsidy that will never appear in a budget document, be voted on, or be costed publicly. It is delivered by loosening a standard. No cheque, no line item, no number — but a real reduction in what the province will collect and a real reduction in what companies will pay.

Worth noting on the other side: the same agreement introduced a credit price floor (rising from $60 in 2030 to $110 in 2040) and a headline price path ($95 → $100 in 2027 → $115 in 2030 → $130 in 2035 → $140 in 2040). The governments' own framing was that Canada's carbon credit markets were not working — an oversupply of low-priced credits had weakened incentives. So the package tightens in some places while loosening in others. But the loosening is targeted precisely at the five companies receiving the subsidies.

1.3 — The channels, itemized

A. Federal tax expenditures (foregone revenue)

CCUS Investment Tax Credit — capture equipment 50% Refundable credit

CCUS ITC — transport, storage, use equipment37.5%Refundable credit

New: Enhanced Oil Recovery ITC — capture equipment25%Refundable credit

New: EOR ITC — transport, storage, use18.75%Refundable credit

The critical change in this agreement: those 50%/37.5% rates were scheduled to expire in 2030. They now run to 2035 — precisely matching Pathways' construction window.

Scale. The PBO estimated the CCUS ITC at $5.7 billion to 2027-28, about $1 billion above Finance Canada's own $4.6 billion forecast. Environmental Defence puts the running cost at up to $12.4 billion by 2035. One independent analysis estimated the extension's value at roughly $1 billion per year, with Pathways alone accounting for about 80 per cent of it — projecting the consortium could receive $7–8.5 billion in credits over its first decade, dwarfing every other industrial CCS project in Canada. All of these are estimates, not caps.

B. Alberta's Carbon Capture Incentive Program — cash, not foregone revenue

To answer the question directly: yes. ACCIP is a grant, not a tax measure. This distinction matters and it cuts in an interesting direction.

The program provides 12 per cent of new eligible CCUS capital costs, paid to operators as cash in three installments over three years, beginning one year after operations start, under a signed grant agreement with the province — structured on the model of the Alberta Petrochemicals Incentive Program. Alberta has now committed to extend it to 2035 specifically for Pathways.

Program scale: $3.2 billion to $5.3 billion in support between 2024 and 2035. It is explicitly stackable with the federal ITC — the same dollar of capital cost can draw both.

Three observations a taxpayer organization should make:

1. It is money out the door, appearing as provincial expenditure. In transparency terms this is better than an uncapped tax credit: grants require an agreement, milestones, reporting between installments, and a negotiated amount based on a Class 3 cost estimate. There is a real ceiling per project.
2. But it is partly funded from the TIER fund — the pot filled by industrial emitters buying fund credits at $95/tonne. So a portion of this is not general tax revenue; it is carbon compliance money recycled back to large emitters. Whether that is "taxpayer money" is a fair debate. What is not debatable: it is public money with an opportunity cost. Every dollar of TIER fund money paid to the five largest oilsands producers is a dollar not available for anything else — and the same producers are among the largest contributors to that fund. It is, in part, a closed loop.
3. The payment timing is genuinely prudent design. Grants flow after one year of operations, not during construction. Alberta is not funding a hole in the ground. Credit where due.

C. Operating subsidies — the newest and least-quantified channel

For years the industry argued capital support wasn't enough; it wanted help with running costs. This agreement delivers. Ottawa agreed "to advance financing to support operating costs for CCS projects," including changes to the Clean Fuel Regulations guaranteeing a minimum 20 per cent credit creation rate for upstream CCUS — a saleable revenue stream. Ottawa is also "potentially exploring financing for CFR related projects by federal investment agencies."

The MOU backgrounder does not specify what those changes would include. No number is public.

D. Carbon Contracts for Difference

The Implementation Agreement commits Canada and Alberta to jointly fund CfDs covering up to 75 million tonnes of emissions reductions, cost-shared equally, up to a maximum liability of $600 million per party — $1.2 billion total.

Two features worth flagging. First, there is a stated cap here — better design than the ITC. Second, the agreement contains a policy-risk clause: if Ottawa repeals the federal carbon pricing backstop, Canada assumes sole liability; if Alberta repeals TIER, Alberta assumes sole liability. In effect, each government has written the other an insurance policy against its own future policy reversal — and taxpayers underwrite both.

E. Foregone carbon revenue

The TIER tightening rate concession described in 1.2 — from 2 per cent to 1 per cent for compliant companies. Uncosted, unpublished, and not appearing in any budget as support.

F. Production subsidies

Alberta agreed to "implement financial supports to encourage the oil production growth required to underpin" the new pipeline and other expansions. Unquantified. This is a subsidy whose explicit purpose is to generate enough volume to justify the pipeline taxpayers are building.

G. The pipeline equity itself

$35.2–43.7 billion, 90 per cent public. Terms undefined. Premier Smith conceded detailed funding plans and the cost to taxpayers remain "to be negotiated" — and that over the coming year the partners will work out "who pays what and how much they borrow."

H. Associated infrastructure

Ottawa has separately committed $10 billion toward upgrading the Roberts Bank port corridor where the pipeline would terminate.

Adding it up

One analysis published in The Hub — not a green outlet — concluded the full package could cost taxpayers upwards of $100 billion when all associated costs are tallied.

And on Pathways' price tag: the official figure remains the 2022-vintage $16.5 billion. Reporting now puts it at over $20 billion, and by one account around $30 billion. When asked about the capital cost, the federal minister's spokesperson said the question was better addressed to the companies.

Recall what an uncapped percentage credit does to that number.

Part 2: What taxpayers are getting for it — the revenue case

A fair assessment has to take the upside seriously. Here is what proponents project, and what can be verified.

The claims

• Alberta's submission cites previous estimates for a similar past project showing potential for as much as $3.8 billion in total annual government revenues across Canada.
• The federal government projects Pathways generating $16.5 billion in GDP, $12.2 billion in labour income, and up to 43,000 jobs annually.
• Prime Minister Carney said the pipeline would "catalyze" more than $200 billion in investments — and called that a "lowball figure."

The verifiable mechanism: the differential

This is the strongest part of the revenue case and deserves to be understood rather than dismissed.

Alberta heavy crude sells at a discount to the US benchmark — the "light-heavy differential." Because Alberta is a captive seller into one market, that discount is partly a function of limited export capacity. Alberta's own budget quantifies the sensitivity:

Every US$1/bbl narrowing in the light-heavy differential is worth roughly $670 million in annual provincial revenue. Every US$1/bbl movement in WTI is worth roughly $680 million.

The Trans Mountain expansion is the proof of concept, and the evidence is real: the WCS–WTI spread narrowed substantially after TMX opened, and one bank analysis found that without that narrowing, Alberta's 2025-26 deficit would have been $10.5 billion instead of $6.4 billion — a roughly $3.9 billion swing in a single year. That is a serious argument for egress capacity, and it should not be waved away.

The problem with repeating the trick

Here is the complication for the revenue case — and it comes from the same analysis.

With the differential now roughly at fair value — Canadian oil is arguably no longer sold at a meaningful discount — any further narrowing of the WCS–WTI spread is very unlikely.

If that assessment holds, the central fiscal argument for the new pipeline weakens considerably. TMX captured the differential gain. You cannot capture it twice. A second line adds capacity and optionality, and it insulates against future bottlenecks as production grows — but the specific, large, quantified windfall that TMX delivered came from closing a discount that was already there. That discount has largely closed.

This deserves to be the sharpest question put to proponents: if the differential is at fair value, where does the return on $35–44 billion come from? The honest answers are tolls, incremental royalty from incremental production, and insurance against future discounts — all real, but none of them the $670-million-per-dollar arithmetic that gets quoted.

The Trans Mountain precedent, honestly stated

For the defence: TMX reached full capacity two years after launch. In Q1 2026 alone it paid Ottawa $448 million — $148 million interest, $300 million dividends — and has returned $2.2 billion in cash to Canada since May 2024. Proponents stress it was financed against the federal AAA credit rating and is being paid off through tolls from producers, not taxes.

For the prosecution: Ottawa bought it for $4.5 billion in 2018 after Kinder Morgan walked away. The expansion was estimated at $7.4 billion in 2017. It came in at $34 billion — an overrun one University of Calgary economist called "almost unprecedented." It remains unclear how those costs translate into tolls, and the federal government cannot find a buyer.

The synthesis: the bull case rests on TMX's operating record; the bear case rests on its construction record. The new line is longer (1,200–1,250 km), more expensive, and — unlike TMX in 2018 — starts with no confirmed customers.

Part 3: The six fiscal risks

1. Cost overrun risk sits almost entirely on the public. With 90 per cent public ownership and a private partner explicitly declining to risk capital pre-FID, no meaningful private balance sheet absorbs overruns. The comparable project overran by 360 per cent. And through the uncapped ITC, overruns on Pathways automatically increase the federal subsidy too — the public is exposed to escalation on both halves of the package.

2. There are no shippers. The pipeline has no confirmed customers. Building 1,200 km of infrastructure on public money before securing volume commitments inverts the normal commercial sequence, in which shipper contracts precede construction.

3. Nothing is binding. The July agreement is a non-binding MOU. Binding agreements with each of the five companies are due on or before November 15, 2026. Governments have made concrete fiscal commitments against corporate commitments that are, as of today, aspirational. Pathways has been "awaiting a final investment decision" since 2022.

4. Demand risk is real and long-dated. The asset must serve Asian markets for decades. Critics argue the private sector's absence is itself the market signal. One can dispute the forecast; one cannot dispute that private capital declined the bet and public capital took it.

5. The subsidies compound rather than substitute. The federal ITC, the Alberta 12 per cent grant, the EOR credit, the CFR credit floor, the CfD, and the TIER stringency break all stack. No public document sets out the combined effective public share of Pathways' capital and operating costs. In 2022, the consortium's opening ask was for governments to cover 75 per cent of costs.

6. The deliverable shrank while the price grew. The 2021 public pledge was 68 megatonnes of annual reductions. The figure in these agreements is 16 megatonnes by 2045, with a 6 Mt minimum in service by 2035 — a 77 per cent reduction from the original promise, arrived at while the cost estimate roughly doubled and the subsidy package expanded.

As Pembina's Janetta McKenzie put it: "That's a pretty big package for emissions reductions, particularly given that this project has shrunk so much."

Whatever one thinks of the climate merits, paying more for less is a value-for-money problem.

Part 4: The revenue trap — why a good year is the worst argument

There is a temptation to wave all of this away by pointing at the treasury. Alberta tabled Budget 2026 on February 26 with a $9.4 billion deficit, built on an assumption of US$60.50/bbl WTI. Two days later, the US and Israel attacked Iran. The Strait of Hormuz — through which roughly one-fifth of the world's crude travels — closed. WTI surged from the low $60s to average around $90, at points trading above $100.

At roughly $680 million of provincial revenue per US$1/bbl, the arithmetic is violent. University of Calgary economist Trevor Tombe calculated Alberta was posting $40–60 million daily surpluses and estimated the province could flip its projected $9.4 billion deficit to roughly a $4 billion surplus. Alberta may well finish this year in the black.

This is not an argument for the deal. It is the argument against the deal's logic — and it should be uncomfortable reading for both sides.

What the windfall actually demonstrates

Consider what just happened. A budget was tabled. Forty-eight hours later, a war on the other side of the planet swung the province's fiscal position by thirteen billion dollars — with no policy change, no economic reform, no decision by any Albertan. The province's finance minister declined to revise the forecast at all, on the reasonable ground that "we do not plan based on short-term fluctuations in the market."

That is a candid admission of something important: the number in the budget and the number in the bank are only loosely related, and the government knows it.

A windfall arriving from a closed strait is not a business plan. It is weather. And the correct response to a lucky year is not to lever into the thing that made you lucky.

The structural problem, stated plainly

Non-renewable resource revenue is forecast at $13.2 billion in 2026-27 — 18 per cent of total provincial revenue, the third-largest source after personal income tax and federal transfers, and ahead of corporate tax. The WTI price required to balance the budget ranges from US$74 to US$77 — against private-sector forecasts in the $50–60 range and a budget assumption of $60.50.

Charles St-Arnaud of Servus Credit Union named it precisely: if the break-even oil price sits persistently above the realistic price, that is "a structural deficit." Peter Tertzakian's colleagues in the sector have made the same point for decades. As one veteran analyst put it after 40 years of watching this cycle: we do OK when prices are high and post small surpluses; as soon as prices go down we end up with big deficits — we need a better revenue structure.

The RBC assessment is that Alberta's fiscal advantage is eroding: net debt heading to $137.5 billion by 2028-29, with net debt-to-GDP climbing to 12.9 per cent from 7.2 per cent in 2024-25 — the highest since the pandemic. Budget 2026 also abandons the province's own fiscal framework, which requires deficits to be consolidated within three years.

Why this package makes the trap deeper, not shallower

Every element of this agreement increases the share of Alberta's fiscal future that rides on a commodity price the province does not set:

• The stated goal is to double oil production to 8 million barrels per day over ten years. That is a deliberate decision to make an already-concentrated revenue base more concentrated.
• The pipeline is a 40-year bet on one commodity, one product, and largely one customer region, financed by governments whose revenue already rises and falls with that commodity. This is the opposite of a hedge. When oil falls, royalties fall and volumes fall and toll revenue falls and the asset's value falls — all at once, in the same direction. Alberta is buying more of the risk it already has too much of.
• The subsidies are paid in the bad years too. ITC obligations, grant installments, and CfD payouts do not pause when WTI drops to $50. In fact, a CfD is most expensive precisely when carbon and energy markets are weak — that is its entire purpose. The support is countercyclical; the revenue is procyclical. The public pays most exactly when it can least afford to.
• Even the upside has a clawback. Under Alberta's Fuel Tax Relief Program, the 13-cents-per-litre fuel tax lifts automatically once WTI averages above US$90 — so the windfall partially cannibalizes another revenue line.

The question to put to both governments

The current surplus, if it materializes, was produced by a war. It will not repeat on schedule, and no one in Edmonton or Ottawa planned it, forecast it, or earned it.

If a $13 billion swing can arrive in 48 hours from an event no Albertan influenced, what is the argument for committing $35–44 billion of public capital — plus an uncapped tax credit, a $1.2 billion price guarantee, and $3.2–5.3 billion in grants — to deepen exposure to that same variable?

The strongest version of the government's answer is that new egress reduces volatility by removing the differential risk (see Part 2). That is a serious answer, and it is weakened considerably by the evidence that the differential has already largely closed.

The renewed public conversation about a provincial sales tax — triggered, notably, by this very budget — exists because Albertans across the political spectrum increasingly recognize the underlying problem. This package answers that conversation by doing the reverse.

Part 5: The strongest counterarguments

Intellectual honesty requires stating the other side at full strength. Several are serious.

1. TMX is empirically returning cash. Not theory: $2.2 billion since May 2024; $448 million in a single quarter. The debt is serviced by tolls from producers, not taxes. If the new line replicates that, "taxpayer on the hook" describes a financing structure, not a loss.

2. Sovereign borrowing is the cheapest capital available. The federal AAA rating means Ottawa finances at rates no private proponent can match. For infrastructure with 40-year lives and utility-like toll revenues, public financing may be the fiscally rational structure. Refusing on principle costs money.

3. Egress genuinely is Alberta's highest-leverage fiscal variable. Even if the differential is near fair value today, that is partly because TMX exists. Production is forecast above 4.3 million bpd by 2027. Without matching egress, the discount returns — and at ~$670 million per dollar, preventing its return is worth billions annually. On this reading the pipeline is insurance against re-widening, not a bet on re-narrowing. That is a materially stronger argument than the one usually made, and proponents should make it.

4. Market failure may be the actual diagnosis. Smith attributes private reluctance to the graveyard of Northern Gateway, Energy East, and Keystone XL — regulatory and political risk, not commercial risk. Analysts including Heather Exner-Pirot argue the upside from tolls, taxes, and royalties makes it a "slam dunk on the economic side" once de-risked.

5. ACCIP is well designed. Capped per project, negotiated against a Class 3 estimate, paid only after operations begin, with reporting between installments. If all the support looked like this, the transparency objection would largely dissolve.

6. The counterfactual isn't zero. Alberta's royalty base is exposed either way. Doing nothing has a fiscal cost too.

Where the counterarguments are weakest

The TMX cash-return defence describes an asset bought at $4.5 billion and expanded at $34 billion against a $7.4 billion estimate — returning $2.2 billion over two years. Returning cash and earning a return on $38.5 billion of public capital are different claims.

And crucially: the toll-financing defence does not extend to most of this package. Tolls may service pipeline debt. Tolls do not repay the ITC, the grants, the CfD, or the foregone TIER revenue. Those are transfers with no repayment mechanism at all — and they are the majority of the mechanisms in Part 1.

Part 6: What to demand before November 15

1. A published total. No document states the combined public contribution across all eight channels. Demand one before binding agreements are signed.
2. A cap on the CCUS ITC. The PBO flagged the absence of an upper limit. Fix it — or at minimum, cap eligible costs at the project's stated estimate so overruns don't automatically escalate the subsidy.
3. A PBO costing of the full package — pipeline equity, Roberts Bank, ITCs, grants, CfDs, and foregone TIER revenue — before the deadline, not after.
4. A published costing of the TIER stringency concession. Alberta halved a tightening rate for its five largest emitters. What is that worth to them, and what does it cost the province? There is no public number.
5. Shipper commitments before construction. No public capital deployed without contracted volumes.
6. Overrun allocation in writing. Who eats escalation above $43.7 billion? Answer before signing, not during construction.
7. Disclosure of Alberta's "financial supports" for production growth. Currently undefined and unbounded.
8. Clawbacks tied to delivery. If the 6 Mt minimum slips, the subsidies should slip with it.