The fiscal roller coaster of oil prices is headed up, up, up for Alberta, Saskatchewan and Newfoundland.
All three energy-producing provinces have unveiled much improved revenue numbers in the past week, driven by the rebound in crude prices. But the lurch upward is most breathtaking in Alberta, where the deficit is plummeting – and a surplus is even possible next year.
It is fiscal whiplash from February, when the Alberta government projected a massive $18.2-billion deficit, regretfully conceding that “... it is no longer feasible to balance the budget by 2022-23.″
What a difference nine months, and a global recovery in oil demand, has made. This week, Alberta said its deficit is projected to come in at just $5.8-billion for the current fiscal year of 2021-22. Most of that swing is driven by a $10-billion increase in expected non-renewable resource revenue, as the chart below shows.
The fiscal picture is also brighter for the next two fiscal years, with a projected deficit of $11-billion in 2022-23 and $8-billion in 2023-24 now forecast to be $3.3-billion and $2.3-billion, respectively. And that is only using the middle-of-the-road scenario contained in the midyear fiscal update, issued on Tuesday.
The province also outlined a high-growth scenario, including higher oil prices, that would add $6.6-billion in revenue in the coming fiscal year.
That would be enough to push Alberta back into a surplus position, notes University of Calgary economist Trevor Tombe. “It would indeed be the S-word,” he said, adding that the province’s crude-price estimates are, if anything, on the conservative side.
Prof. Tombe said the provincial government may not have wanted to flaunt the possibility of a balanced budget without the certainty of being able to achieve it. Crude prices are notoriously volatile: Witness the steep drop in future prices in the past two weeks on fears that the Omicron variant of the coronavirus will stall global economy recovery, and reverse growing oil demand.
Robert Hogue, senior economist at the Royal Bank of Canada, said he viewed Alberta’s assumptions as prudent, given the recent downturn in oil prices.
However, Bank of Nova Scotia senior economist Marc Desormeaux said there is potential for a further fiscal upside for Alberta.
Alberta’s energy revenue has always been a bit of a roller-coaster ride, but the gyrations are getting bigger, as the oil sands sector matures. Three decades ago, the province instituted an ultra-low royalty regime designed to spur capital investment in bitumen production. While complicated, the heart of the program is to keep royalty rates low until a project reaches payout status – when its cumulative revenue exceeds its cumulative costs, including capital investment.
The difference in royalty rates is enormous. Prepayout, royalties range from as low as 1 per cent of gross revenue to 9 per cent. After payout, the potential royalties rise sharply, to between 25 per cent and 40 per cent of a project’s net revenue (after operating, capital and other costs are deducted from gross revenue).
More and more oil sands projects are entering the postpayout phase, which has two important consequences. Most obviously, it increases Alberta’s non-renewable resource revenue. But it also has the effect of magnifying the volatility of that revenue.
In fiscal 2008-09, for instance, Alberta took in $3.3-billion of bitumen revenue, when the oil sands were producing 1.4 million barrels a day, and West Texas Intermediate oil averaged US$85.50 a barrel. Fast forward to this year, with a much lower price projection of US$70.50 – and forecast bitumen revenue of $7.6-billion.
Part of that gap is explained by the projected growth in bitumen output by 3.2 million barrels a day. But the growth in provincial revenue outstrips the growth in production, even at lower WTI prices. The reason is that a greater proportion of the oil sands industry is exposed to higher, postpayout royalty rates.
That greater volatility is showing up in the sensitivity of provincial revenue to swings in oil prices, a formal estimate of which appears in the Alberta budget each year. In February, the province said it would gain $230-million for each US$1 increase in the price of WTI.
That sensitivity has always been influenced by the price assumptions that the province makes. Royalty rates are lower when prices are lower and rise as prices rise. That means at higher price levels, the province will gain more revenue from a $1 increase in the cost of a barrel of oil than it will from a $1 increase at lower levels. (In essence, it is the equivalent of a progressive income tax, where higher earners don’t just pay a higher amount of tax, but also a higher rate.)
But the maturation of the oil sands adds to that volatility, since there is such a steep jump in payments once a project reaches payout, Prof. Tombe notes. As the chart below shows, that has contributed to Alberta’s sensitivity estimates rising over the past decade, even as the underlying price estimates fluctuated.
Even the somewhat lower sensitivity estimate for the current 2022 fiscal year is higher than any pre-2018 figure. And that sensitivity is based on the now-outdated price projections from February. Prof. Tombe said that the province’s November update indicated that it would gain $284-million in revenue for each dollar increase in the price of oil from its base estimate of US$70.50 a barrel to its high-growth scenario of US$74.50 a barrel.
Without the amplifying presence of Alberta’s oil sands, Saskatchewan, and Newfoundland and Labrador have marked more modest gains from their original budget forecasts.
In Saskatchewan, oil revenue is now projected to hit $745.5-million, up from the budget’s forecast of $505.1-million. The province boosted its price projections for WTI in line with Alberta’s – but each US$1 increase only adds $14-million to provincial coffers.
It’s a similar story in the East, where Newfoundland gains $19-million for each US$1 increase in the price of Brent crude. The province’s potential fiscal gains were constrained, however, by decreases in oil production.
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