For most of the past decade, natural gas has been the quiet corner of Alberta’s energy story. Oil gets the headlines. Gas just keeps the lights on and the furnaces running.
That’s changing.
ATB Financial is forecasting Alberta natural gas prices to strengthen to $3.30 per mmBTU “this year, up from roughly” $1.70 in 2025, a near doubling. Deloitte is slightly more conservative at $2.95, but the direction is the same. And the Alberta government’s own Budget 2026 assumes the reference price recovers from $1.70/GJ to $3.00/GJ, driving natural gas royalty revenue up 29% to $942 million.
The question every finance team should be asking: what’s actually driving this, and is it durable?
What’s Behind the Move
Unlike previous price rallies, this one isn’t being driven by a single project or a supply shock. It’s a combination of forces pulling in the same direction.
Supply discipline is holding. After years of low prices, producers cut back. Drilling activity in gas-weighted plays slowed materially through 2024 and 2025. That restraint is now showing up in the supply picture.
Demand is growing from multiple directions. Power generation is the big one. Alberta’s coal phase-out has shifted baseload demand toward natural gas. Add industrial demand, and you get a firmer floor under pricing than we’ve seen in years.
Storage is tighter than expected. Western Canadian storage has been drawn down faster than forecast through the summer months, leaving less cushion heading into winter.
The broader North American balance has tightened. U.S. gas demand from power generation, industrial use, and exports has grown, which pulls on Canadian supply indirectly. AECO doesn’t trade in isolation, it responds to what’s happening south of the border.
The result is a market that looks structurally firmer than it has in years. Not a spike. A reset.
What This Means for Gas-Weighted Producers
Higher prices sound like good news, and they are. But for finance teams, a rising price environment brings its own set of planning challenges.
1. Hedging Becomes a Strategic Decision, Not a Formality
When AECO was trading below $2, hedging was mostly about survival. At $3.30, it’s about optimization.
Look at how the smart operators are handling it. Peyto Exploration recorded $36.7 million in realized hedging gains “in Q2 2026 and has hedged approximately” 505 MMcf/d at $4.02/Mcf for the second half of 2026, well above the current forecast. That’s not defensive hedging. That’s locking in upside.
Cavvy Energy has 68,394 GJ/d of its remaining 2026 production hedged at a weighted average of “$3.38/GJ”. Pine Cliff Energy has roughly 37% of gross gas production hedged at about $3.19/Mcf.
The finance teams that are winning right now aren’t just hedging to protect the downside. They’re modeling the upside and deciding how much of it to secure.
Action item: Reassess your hedge book against current strip pricing. Are you leaving too much on the table? Or are you over-hedged in a rising market? Run the scenarios.
2. Capital Allocation Gets Harder, Not Easier
When prices are low, capital discipline is easy, you don’t have much choice. When prices rise, the temptation to accelerate spending is real.
Tourmaline cut its 2026 capital budget by $350 million in March when AECO prices were still weak. Now, with prices recovering, the company is forecasting higher free cash flow for 2026 and 2027. Peyto is holding its $450–$500 million capital program steady, adding 43,000–48,000 boe/d of new production by year-end.
The lesson? Rising prices don’t mean abandoning discipline. They mean being more deliberate about where capital goes, because the opportunity cost of a bad investment is higher when cash flow is strong.
Action item: Stress-test your capital program against multiple price decks. What happens if AECO holds at $3.30? What if it drops back to $2.50? What if it climbs to $4.00? Your capital plan should hold up across all three.
3. Cash Flow Forecasting Needs a Wider Range
Every $0.10/Mcf change in AECO pricing can swing free cash flow by tens of millions of dollars. Tourmaline estimated that each 10-cent improvement in AECO pricing would increase its 2026 free cash flow by “C$45 million”.
That sensitivity cuts both ways. Finance teams that built their 2026 budgets on $2 AECO assumptions are now looking at materially better numbers. But those same teams need to ask: what if prices pull back?
The forward curve is not uniformly bullish. Some analysts expect AECO to average “$2.20/mmBTU in the second half of 2026” before rising to $3.50 in 2027. Western Canadian production has also hit record levels above 20 Bcf/d, and pipeline egress constraints remain a real limitation on how much gas can actually reach higher-priced markets.
Translation: the trend is positive, but the path won’t be linear.
Action item: Build your cash flow model with a price band, not a point estimate. Model $2.50, $3.30, and $4.00 AECO. Know where your break-even is and where your capital flexibility kicks in.
4. Royalty Planning Gets More Expensive—And More Important
Higher prices mean higher royalties. Alberta’s natural gas royalty revenue is projected to rise 29% to $942 million in 2026-27. That’s good for the province, and a direct cost for producers.
Finance teams should be modeling royalty sensitivity alongside price sensitivity. The interplay between price, royalty rates, and netback can be counterintuitive: a higher headline price doesn’t always translate proportionally to the bottom line.
Action item: Recalculate your netback at multiple price points. Confirm your royalty assumptions with your marketing and land teams. Build royalty sensitivity into your monthly variance analysis.
The Constraint Nobody’s Talking About
Here’s the uncomfortable part of the story: higher prices don’t help if you can’t get your gas to market.
Western Canada’s pipeline egress has been a bottleneck for years. Production has grown, but takeaway capacity hasn’t kept pace in every corridor. That means producers can be price-takers in periods when local supply outpaces what the system can move.
The companies that are best positioned are the ones with firm transport capacity, diversified market access, and the ability to redirect volumes when spreads widen between basins.
Action item: Review your firm capacity position against your production forecast. Where are you exposed to egress risk? What’s your plan if local differentials blow out?
The Strategic Question: Are You Positioned for the Upswing?
Alberta’s gas producers have spent years operating in a low-price environment. They’ve cut costs, optimized operations, and learned to do more with less. That discipline is now paying off, but only for those who can pivot from survival mode to growth mode without losing their edge.
The finance leaders who will thrive in this environment are the ones who:
- Understand the sensitivity of their cash flow to price movements
- Maintain discipline in capital allocation even when cash is flowing
- Use hedging strategically, not reactively
- Plan for volatility, not just the base case
- Know their egress exposure and how it affects realized pricing
At BullsEye Recruitment, we’re seeing increased demand for finance professionals who can navigate this kind of complexity—people who understand commodity price risk, can build robust financial models, and can communicate clearly with operations and executive leadership.
The gas market is strengthening. The question is whether your finance function is built to capture that upside.
About BullsEye Recruitment Inc.
BullsEye Recruitment Inc. is a Calgary-based boutique recruitment firm specializing in placing experienced accounting and finance professionals at senior levels. We understand the Alberta economy, the energy sector, and what it takes to find the right people the first time.
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