Scaling the Utility-Scale BESS Business Through US Market Expansion
Utility-scale BESS is one of the fastest-growing grid assets in North America, and this case study examines how an established infrastructure firm decides whether to scale that business through the United States. The protagonist, Aecon, is a Canadian infrastructure and development company fresh off completing Canada's largest battery storage project. The strategic question is whether to replicate that success in the volatile but lucrative ERCOT market in Texas, and how to structure the move.
From Oneida to a US Growth Decision
Aecon operates through two segments: construction, covering civil, industrial, utilities, nuclear and urban transport work, and concessions, where it takes equity stakes in project ownership consortia and public-private partnerships. Its flagship battery achievement is the Oneida Energy Storage Project in Ontario, a 250 MW / 1 GWh facility that ranks among the world's largest built battery storage projects. Aecon played a dual role there, acting as the turnkey engineering, procurement and construction (EPC) contractor while retaining an equity stake to align incentives. Backed by a 20-year capacity contract with Ontario's system operator, the project moved from construction in 2023 to operation in 2025, delivered ahead of schedule and roughly 100 million dollars under a 700 million dollar budget. That record established the firm as a credible EPC-plus-equity partner. With Canada's construction market slowing and margins tightening, the executive team faces a choice: stay with the familiar contract-driven, capacity-market model or build a new power division targeting the merchant US market.
Why ERCOT, and What Makes It Risky
Texas has become the leading global BESS market and the epicentre of utility-scale battery deployment in the United States, driven by market momentum and merchant ambition rather than subsidies. Its energy-only structure creates significant price volatility, opening lucrative energy arbitrage and ancillary service opportunities, while high solar and wind penetration increases the need for storage. The pipeline is vast, with around 178 GW queued for interconnection and 35 GW already interconnected. Commercially operational capacity reached about 12 GW / 19.4 GWh by September 2025. Rapid load growth from artificial intelligence and data centres adds urgency, with one estimate suggesting data centres could account for half of peak demand growth by 2030. Crucially, many developers need reliable EPC-plus-co-investor partners to scale quickly, which is precisely the gap Aecon can fill.
The risks are equally clear. ERCOT is purely merchant-based with no capacity market, so revenues are volatile and inconsistent, unlike Ontario or California. Ancillary services once produced the biggest returns but have saturated, and wholesale trading from real-time and day-ahead energy markets now makes up more than half the revenue stack. Nodal pricing means locational precision near load centres or congested zones strongly affects returns, and the market is adding complexity such as real-time co-optimisation. Broader US uncertainty around tariffs, supply chains, policy, permitting and interconnection compounds the picture.
Balancing What Works Against a New Frontier
The strategic tension is between exploiting a proven model and exploring a new one. Aecon has shifted toward lower-risk contracting, with roughly 76 percent of its backlog on cost-plus or unit-price terms versus 24 percent fixed-price, which limits exposure to cost overruns. Its financial strength is genuine, reported third-quarter 2025 revenue of 1.53 billion dollars beat forecasts by about 10 percent, a 20 percent year-over-year rise, and the firm holds a record backlog near 10.8 billion dollars. The decision is whether to enter ERCOT as a new independent power producer, whether to acquire an early-stage development pipeline, and how much at-risk exposure to accept. The shift toward wholesale trading revenue favours longer-duration systems of two to four hours, which capture wider arbitrage spreads and higher projected returns.
What It Means for Infrastructure Firms
The case illustrates a wider pattern: incumbent infrastructure companies must periodically reinvent their business models as energy systems, policy and technology shift. For Aecon, the EPC-plus-equity approach that worked under a contracted Ontario framework needs adaptation for a merchant market with different revenue mechanics. Success depends on siting precision, disciplined risk appetite and choosing project archetypes and durations suited to arbitrage-led revenue. It is a practical study for any developer or contractor weighing entry into utility-scale storage in the United States.
Key Takeaways
The Oneida project proved the firm can build and co-own grid-scale storage, delivered ahead of schedule and about 100 million dollars under budget.
ERCOT is the leading global BESS market, with roughly 178 GW queued and around 12 GW operational, driven by merchant dynamics not subsidies.
Data centre and AI load growth could drive half of peak demand growth by 2030, strengthening the case for storage.
ERCOT's lack of a capacity market makes revenue volatile, with wholesale trading now over half the revenue stack after ancillary services saturated.
Nodal pricing makes siting near load centres or congested zones decisive for returns.
Longer-duration two to four hour systems better capture arbitrage spreads, favouring a different project design than a
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