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Anova Energy, Suite 1902 102A Tower, 10025 102A Avenue NW Edmonton, Edmonton, AB (2026)

06/02/2026

One of the most notable trends we are monitoring at Anova Energy in ’s power market is the growing volatility ⚡.

In May 2026, Alberta recorded approximately 150 hours at $0/MWh, the highest level ever seen for a May, up from 40 hours in 2024 and 70 in 2025—an increase of 275% driven by rising renewable generation and recurring supply surpluses.

At the same time, the market also reached extreme upside pricing, including the $999.99/MWh cap on May 25, followed by five consecutive hours above $900/MWh on May 27 and eight on May 28, signaling a clear shift toward more frequent price extremes!

This pattern of deep negative-to-zero pricing pressure on one side and repeated near-cap pricing on the other marks a new phase of structural volatility in Alberta’s market⚡.

As Alberta transitions to the Restructured Energy Market (REM), where the offer cap will rise to $1,500/MWh at launch in mid-2027 and peak price levels are expected to be higher than today, understanding and managing these swings will become increasingly critical for commercial and industrial energy consumers.

📊At , we actively monitor these dynamics to help clients interpret exposure, pricing signals, and emerging risk trends.

For businesses exposed to electricity prices, the focus is no longer simply on whether prices are high or low, but on managing a market that can move from zero to near $1,000/MWh within days.

Contact the Anova team at [email protected] for further insights or support.

05/25/2026

One of the more important energy developments in Canada this month may not be getting enough attention from large industrial consumers.

On May 15, 2026, the federal government and Alberta signed the Implementation Agreement tied to the Canada-Alberta energy MOU, adding further clarity around industrial pricing, energy infrastructure, and long-term market direction.

The agreement increases visibility on Alberta’s industrial carbon price trajectory, with a path rising from roughly $100/tonne in 2027 toward $130/tonne by 2040. It also confirms the introduction of a price floor for TIER credits starting in 2030.

📈 This structural change is already showing up in forward markets, with upward pressure on the back end of the curve. As a result, 3 to 5 year hedge offers have moved higher, despite near-term fundamentals remaining well supplied.

Market interpretation is also diverging. Retailers and generators are taking very different views on how carbon policy and supply adequacy will flow through to pricing, which is driving noticeable variation in contract structures and rates.

For large electricity and natural consumers, the key point is that policy, pricing, infrastructure, and load growth are now tightly linked to forward price formation, not just short-term supply-demand dynamics.

☝️This is a good moment to review strategy and ensure you have a clear view of how different market assumptions are being priced into offers.

At Anova Energy, we help consumers interpret these signals and structure strategies aligned with their risk profile and load requirements.

📩 Contact the Anova team at [email protected] for the fastest response.

05/06/2026

’s May 2026 Long-Term Adequacy Report reinforces a theme we’re seeing across the market at Anova Energy: today’s reliability is strong—but the forward outlook is far more conditional.

In the near term, the system is well supplied. The probabilistic shortfall metric remains negligible through April 2028, indicating minimal risk of supply gaps under current conditions.

However, the forward signal is less straightforward.

Alberta’s development pipeline remains large on paper (~19 GW), but project attrition is accelerating, with ~7.6 GW cancelled this quarter alone—primarily across , , and . This raises important questions about how much of the “announced” capacity will actually materialize.

Reserve margins appear healthy (~34% in 2026 with interties), climbing sharply toward 2029–2030 if announced gas projects come online. Without those, the margin flattens. The two mothballed TransAlta coal-era units (Sheerness 1 and Sundance 6, ~800 MW combined) represent a near-term reliability buffer that is counting on.

is shifting from a near-term adequacy story to a mid-term ex*****on risk story. The market is not short today—but it is becoming more sensitive to project delivery, policy clarity, and load growth.

At Anova Energy, we help clients translate these market signals into practical procurement and risk management decisions.

Stay informed with our monthly Alberta Energy Market Update. Subscribe here: https://loom.ly/TpeA8yc

📩 Contact the Anova team at [email protected] for the fastest response!

04/28/2026

Last week in , wind output was high across the province. But not all of that energy reached the market.

Transmission constraints, especially in the southeast where wind resources are strongest, continue to limit delivery.

At the same time, spring demand remains soft. When supply is high and demand is low, Alberta sees surplus conditions:

• Wind offered at $0/MWh
• Thermal and cogeneration units can also bid at $0
• Pool prices fall toward zero

AESO average pool price for April 19–24 sat at average $9.77/MWh, against an average Alberta Internal Load (AIL) of roughly 10,231 MW.

Looking ahead, the Alberta Electric System Operator REM will introduce locational pricing. Revenues will depend on where power is generated, not just when.
That creates a clear challenge. The best resource regions are often the most constrained, which puts additional pressure on realized prices.

Strong generation does not always translate into strong revenue in Alberta’s current and future market structure.

04/14/2026

Alberta power markets are once again demonstrating just how tightly coupled supply fundamentals and price volatility have become.

As of 09:13 AM on April 13, pool price spiked to ~$950/MWh, driven by a classic but impactful combination:

✔️ Minimal wind generation across the province. Total net generation on April 13 was 563 MW out of a 5,684 MW maximum capacity.

✔️ A planned outage at Shepard (EGC1) — ’s largest natural gas-fired facility. Shepard represents ~860 MW of baseload capacity, and notably contributes ~42% of its generation to the under current conditions. Its temporary removal is material from both a capacity adequacy and price formation standpoint. This results in a steeper marginal cost curve, where the clearing price is being set by significantly more expensive units.

This is a clear example of Alberta’s energy-only market design functioning as intended, where price signals respond immediately to intermittency and thermal availability constraints.

's monthly newsletter: https://loom.ly/TpeA8yc

03/31/2026

LNG demand is starting to have a meaningful impact on the Western Canadian natural gas market.

Even with still sitting in a weak range short-term, what’s happening on the West Coast is becoming harder to ignore.

Here’s what stands out right now:
🔹 Western Canadian Storage sits at 86.8% (as of March 17), down 27% since November. This is a typical seasonal draw, but still worth noting given the record high starting levels (120.5%).
🔹 LNG Canada is running near full capacity (~14 MTPA) and steadily increasing shipments to Asia.
🔹 They’ve already shipped their 50th cargo (February), and March volumes are tracking strong.
🔹 Expansion activity at the marine terminal is now underway.

This is where it gets more interesting.

is now expected to take a lead role in advancing a potential expansion of the Coastal GasLink pipeline, which would double capacity to the coast. A final investment decision is expected by the end of 2026, with cost and regulatory scrutiny still in play, but the direction is clear: infrastructure is aligning with export growth.

According to the Canada Energy Regulator, up to 25% of Canada’s natural gas production could be tied to exports by 2050. Alberta remains at the center of that supply.

Right now, we’re seeing a split market:
🔹 Short-term:
Local oversupply keeps AECO soft
🔹 Longer-term:
LNG is gradually connecting Alberta gas to global pricing

Forward signals are :
🔸 June 2026 AECO: ~$1.70/GJ
🔹 January 2027 AECO: ~$3.11/GJ

natural gas looks to be moving from a regional story to a global one. And LNG is the bridge.

Subscribe to our Monthly Newsletter: https://loom.ly/TpeA8yc

03/13/2026

Alberta’s power supply mix shifted materially between 2024 and 2025, and data from the Alberta Electric System Operator highlights how new gas projects are reshaping the system.

Based on monthly generation by fuel type:

🔹Natural gas: ~61% of generation
🔹Wind: ~24%
🔹Cogeneration: ~12–15%
🔹Hydro: ~4%
🔹Solar: ~8% and growing rapidly

Within this mix, two projects stand out:

🔸 Cascade Power Project (Cascade 1 & 2)
🔸 Base Plant

📈From early 2024 through 2025, these plants ramped up to roughly 1.4 GW of average combined generation — about 10–13% of Alberta’s average system demand. For context, the average Alberta Internal Load (AIL) reached 10,316 MW in 2025.

Cogeneration supplied ~40% of generation in 2025, supported by additional output from Base Plant, while combined-cycle assets increased their share to 27% (up from 19% in 2024) due to Cascade 1 and 2.

Overall, -fired generation supplied 76% of Alberta’s electricity in 2025 — up from 53% in 2018.

This new dispatchable capacity has increased the system supply cushion, helped moderate pool prices, and strengthened grid reliability.

continue to grow, but flexible gas generation remains the backbone of Alberta’s power system.

Stay tuned with !

03/05/2026

Alberta electricity demand changed significantly in 2025 — and the shift looks structural.

📈 Demand Growth & Record Peak

Average AIL: 10,316 MW (+2%)

New peak: 12,785 MW (Dec 11)

The previous record was exceeded 35 times in December.

According to the Market Surveillance Administrator report (Feb 2026), demand growth is being driven by oilsands expansion, population growth, and weather.

Interestingly, the record peak occurred at just $44/MWh, with 2,016 MW of wind generation and a 1,471 MW supply cushion, compared to the $629/MWh spike in January 2024.

💡 Takeaway: Demand is rising, but the system is handling peak load more effectively.

At the same time, demand volatility is increasing, meaning the Alberta market is shifting from managing scarcity risk to volatility risk.

Stay tuned with Anova Energy for our monthly Alberta Market Summary: https://loom.ly/TpeA8yc

02/06/2026

AESO’s latest Long-Term Adequacy Metrics show a system that is reliably adequate, yet increasingly operationally tight where it matters most.

System capacity snapshot:

🔹23,371 MW total capacity
🔹14,173 MW gas-fired (~61%)
🔹7,554 MW wind + solar
🔹271 MW storage

Although Alberta’s development pipeline totals 27,320 MW, only 3,564 MW have received regulatory approval. As a result, most future supply additions remain subject to ex*****on and timing risk.

⚠️This is why reserve margins alone don’t tell the full story. The two-year supply cushion highlights periods of tight daily conditions—particularly in winter—when the system relies on dispatch, interties, and price signals to remain balanced.

💡This is where price risk is born—not from annual reserve margins, but from daily operational tightness. Cold weather drives simultaneous power demand and gas burn, tightening both systems at the same time.

is no longer theoretical but the framework against which adequacy curves are drawn, with negative prices, scarcity adders, and new operational products reflecting a grid increasingly balancing solar ramps, batteries, and industrial load rather than coal and combined‑cycle gas turbines.

🔗Stay informed about Alberta’s energy trends with the Anova Energy Market Monthly Newsletter: https://loom.ly/TpeA8yc

01/27/2026

Natural gas prices are spiking across North America as severe winter weather intensifies demand and disrupts supply, driving a sharp market rally with U.S. futures climbing above $6/GJ — the highest level since 2022 — amid a powerful Arctic blast and Winter Storm Fern sweeping across much of the United States.

This episode is a reminder that, in winter, temperature—not just supply—sets the marginal price, with direct implications for electricity markets, utilities, and end-users exposed to spot pricing.

Western Canada seasonal demand has risen, and storage and regulated rates have moved accordingly.

Key highlights:

🔹Western Canadian storage: 95.9% (as of January 23, 2026), with winter heating demand surging, representing a 20% decline since November 2025 (120.5%)
🔹Regulated Rate (ATCO Gas South): Up to $3.331/GJ for January 2026, representing 29% increase from the November 2025 settle of 2.579/GJ.

Forward market signals:

🔹March 2026 AECO futures: ~$2,37/GJ
🔹January 2027 AECO futures: ~$3.52/GJ

While storage levels and underlying supply remain relatively strong, weather remains the single most important driver of near-term natural gas prices. Sudden cold snaps can quickly overwhelm fundamentals, tightening balances and amplifying price volatility across gas and power markets.

Stay ahead of Alberta’s energy trends with the Anova Energy Market Monthly Newsletter: https://loom.ly/TpeA8yc

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