Q3 2026 | July–September
The North American energy market, in perspective. Global developments, local impacts, practical next steps.
EXECUTIVE PERSPECTIVE
Q3 brought a consequential Canadian LNG expansion decision, a more constrained U.S. capacity outlook and new investments in transmission, generation and storage. For commercial energy buyers, the common lesson is to assess local fundamentals rather than assume every market moves with global crude oil.
At a glance —
GLOBAL OIL
Brent averaged US$91/b in August
US$7/b above July, according to the EIA; Middle East export disruptions contributed to the rise.
EIA, September 9, 2026 — Global Oil Markets
CANADIAN GAS
LNG Canada takes a major expansion decision
Phase 2 FID targets 28 million tonnes of annual LNG capacity, up from 14 million.
LNG Canada, September 28, 2026 — Phase 2 Final Investment Decision
U.S. CAPACITY
PJM flags a 6,831 MW planning gap
Its 2028–29 capacity auction cleared at US$325/MW-day, the approved cap.
PJM, July 14, 2026 — 2028/2029 Capacity Auction Results
GRID INVESTMENT
Saskatchewan and New York advance supply options
New intertie approval in Saskatchewan; storage and renewable contracts in New York.
SaskPower, July 2, 2026 — International Power Line Approval
BUSINESS DEMAND
U.S. electricity sales projected to grow
EIA forecast 4,135 billion kWh in 2026 and 4,211 billion in 2027.
EIA, September 9, 2026 — Electricity Outlook
Global → local —
Oil: The EIA reported that Brent crude averaged US$91/barrel in August, an increase of US$7 over July, amid Middle East export constraints. Higher oil costs can matter for diesel, freight and other operating inputs, but do not mechanically determine North American natural gas or electricity prices.
Gas: The EIA forecast U.S. working storage at 3,969 Bcf by October 31, 2026, 5% above the recent five-year average. This was a September projection, not a measured October inventory. In Western Canada, production, pipeline capacity, weather and LNG demand all matter to local price formation.
Power: The EIA forecast U.S. electricity sales of 4,135 billion kWh for 2026 and 4,211 billion for 2027, citing data centres and manufacturing.
EIA, September 9, 2026 — Global Oil Markets | EIA, September 9, 2026 — Natural Gas Outlook | EIA, September 9, 2026 — Electricity Outlook
Canada — regional developments —
ALBERTA
Natural gas outlook and power-market transition
The Alberta Energy Regulator published its 2026 outlook on September 29. It reported 2025 marketable natural gas production of approximately 11.5 Bcf/d, 3% above 2024. Separately, AESO documented Genesee Repower unit testing in July as Alberta prepares for longer-term market changes.
Why it matters: For gas buyers, production and export-pipeline conditions are central to regional pricing; for power buyers, future market-design changes merit monitoring. Testing is not equivalent to commercial operation.
Sources: AER, AER gas, AESO test, AESO REM
BRITISH COLUMBIA
LNG Canada Phase 2 reaches investment decision
LNG Canada announced on September 28 that its owners approved Phase 2 at Kitimat, targeting a doubling of terminal capacity to 28 million tonnes per year. BC Hydro also announced on August 5 that it was acquiring the Island Generation facility to support reliability on Vancouver Island.
Why it matters: The LNG announcement is a long-term gas-demand development, not an immediate change in local gas prices. BC Hydro’s planned acquisition speaks to peak-period reliability needs.
Sources: LNG Canada, BC Hydro
SASKATCHEWAN
Cross-border electricity interconnection approved
On July 2, SaskPower announced regulatory approval to proceed with two proposed international power lines linking southern Saskatchewan and North Dakota. Once built, the project would increase shared transfer capability from 150 to 650 MW.
Why it matters: Additional import/export options can strengthen resilience and market flexibility, but construction and completion still lie ahead.
Sources: SaskPower
ONTARIO
Capacity procurement targets set for 2027–28
On July 17, the IESO published targets for its 2026 capacity auction: 1,800 MW for the summer 2027 obligation and 1,200 MW for winter 2027–28. The auction itself was scheduled for November 2026.
Why it matters: This is a forward procurement signal for generation, storage, imports and demand response—not evidence that all targeted capacity has already been secured.
Sources: IESO
United States — regional developments —
TEXAS
ERCOT changes how the largest loads connect
ERCOT’s July 8 notice detailed the end of its former large-load interconnection study process and the move toward Batch Zero; on September 9, it began issuing verification requests to qualifying large-load projects. The framework applies to eligible projects of 75 MW or more.
Why it matters: Large-load project reviews can affect timelines for data-centre development and future grid planning. A project in the queue is not necessarily an approved or energized load.
Sources: ERCOT, ERCOT verify
ILLINOIS
600 MW of energy storage contracts approved
Illinois’ first 2026 utility-scale storage procurement resulted in contracts supporting 600 MW of new projects, approved by the Illinois Commerce Commission on September 1. State procurement planning continued during August and September.
Why it matters: Storage may eventually support flexibility and reliability. Retail impacts depend on service territory and procurement design: northern Illinois includes PJM territory, while other areas operate under MISO.
Sources: Illinois, Illinois plan, PJM
NEW YORK
Storage and renewable contracts advance
On September 23, NYSERDA announced contracts for eight bulk-storage projects totalling 950 MW and 13 renewable projects totalling more than 719 MW. The agency expects these resources to enter service over coming years, subject to permits and construction.
Why it matters: More contracted supply and storage can improve future flexibility, but customers should not treat the awards as immediate wholesale-price reductions.
Sources: NYSERDA
OHIO
PJM capacity pressure and a manufacturer debate
PJM’s July auction for 2028–29 cleared at US$325/MW-day, with available committed capacity 6,831 MW below its reliability requirement. On September 3, Ohio regulators asked federal officials not to apply a proposed large-load curtailment framework to traditional manufacturers.
Why it matters: Ohio buyers should monitor future capacity-related costs and emerging rules for large loads. The Ohio position was regulatory comment on a proposal, not a final FERC order.
What this means for businesses —
A change in capacity prices, a new LNG terminal or a global crude rally does not automatically call for the same procurement decision in every market. Business customers should review contract expiry dates, site-level usage and peak demand, risk tolerance, regional gas benchmarks, and total landed power costs before comparing fixed and index options.
For sites renewing in the coming months, start the review early, but make the contract decision against current market indications and business-specific needs—not a general forecast of where prices “must” go.
Next-quarter watchlist —
Late November 2026
Ontario IESO capacity auction, scheduled November 25–26, to secure summer 2027 and winter 2027–28 obligations.
December 2026
PJM’s next Base Residual Auction, for the 2029–30 delivery year, remains a key signal for regional supply and capacity costs.
Winter 2026–27
North American natural gas storage, heating demand and export flows may shift pricing and volatility; EIA expected U.S. stocks to enter winter above the five-year average.
2027 onward
LNG Canada Phase 2 construction milestones and future timelines; distinguish investment approval from operating capacity.
Website-ready feature article —
North America’s Energy Market in Q3 2026: LNG Expansion, Grid Investment and the Business Outlook
Suggested category: Energy Insights • Publication draft prepared October 22, 2026
The third quarter of 2026 offered a useful reminder that North America's energy markets do not move in lockstep. International oil prices responded to supply disruptions, Western Canadian natural gas retained its own supply dynamics, and regional electricity systems focused on a different challenge: meeting demand while adding generation, storage and transmission capacity.
For commercial and industrial customers, these developments reinforce the importance of evaluating energy contracts in the context of each local market rather than reacting to a single commodity headline.
Global oil volatility meets local energy realities
In its September outlook, the U.S. Energy Information Administration (EIA) reported that Brent crude averaged US$91 per barrel in August—US$7 higher than July—as Middle Eastern export constraints tightened the global market. Oil-related disruptions can influence transportation, logistics and fuel budgets across North America. They do not, however, translate automatically into equivalent changes in Alberta natural gas prices or wholesale electricity rates. Those markets have their own supply, storage, transmission and demand conditions.
The EIA also forecast U.S. electricity sales of 4,135 billion kilowatthours in 2026 and 4,211 billion in 2027, citing data centres and manufacturing as important drivers. These are forecasts, not final consumption figures, but they illustrate the scale of the demand being planned for.
Western Canada: a major LNG commitment
On September 28, LNG Canada announced a final investment decision for Phase 2 of its Kitimat, British Columbia, terminal. The expansion is intended to double annual liquefied natural gas export capacity from approximately 14 million to 28 million tonnes. That is a major investment decision—not an announcement that the additional export capacity is already operating.
Over time, greater export capability could create another source of demand for Western Canadian gas. How that translates into Alberta's AECO benchmark will depend on production growth, pipeline availability, storage and the timing of new LNG operations. The Alberta Energy Regulator's September outlook reported 2025 marketable gas production of about 11.5 billion cubic feet per day, up 3% from 2024, underlining the importance of monitoring both sides of the supply-demand balance.
Canadian grids continue to adapt
Electricity infrastructure was another recurring theme. In Alberta, the system operator documented July testing of the Genesee Repower generating units, while work continued toward the province's future Restructured Energy Market. Testing should not be confused with a declaration that new capacity was commercially commissioned, and Alberta's revised market rules are a transition rather than a completed switch.
SaskPower received approval in July to proceed with two proposed Saskatchewan–North Dakota power lines. When completed, the project is expected to increase the shared transfer capability from 150 MW to 650 MW, supporting import, export and emergency options. In Ontario, the Independent Electricity System Operator outlined capacity auction targets of 1,800 MW for summer 2027 and 1,200 MW for winter 2027–28. Both are forward-looking supply and reliability initiatives, not new megawatts already on the grid.
U.S. power markets: demand is testing supply
In July, PJM—the regional grid operator serving Ohio and part of Illinois—reported that its auction for the 2028–29 delivery year cleared at the approved cap of US$325 per megawatt-day. Committed resources and self-supplied capacity were approximately 6,831 MW below PJM's reliability requirement. That shortfall is a planning warning, not a prediction of immediate outages; capacity charges are also only one component of customers' electricity costs.
Other states advanced different responses. Texas transitioned large electricity users into a new ERCOT batch study process in July and issued verification requests in September. Illinois approved contracts for 600 MW of new grid-scale storage in September. New York announced contracts for 950 MW of bulk storage and more than 719 MW of large-scale renewable projects. These projects and processes have different completion timelines; announced or contracted capacity should not be counted as operating supply.
What commercial energy customers should take away
For businesses approaching an energy renewal, the practical response is not necessarily to rush into a fixed rate or to remain on an index product. It is to understand the exposure. Electricity supply, capacity, delivery and local market rules can influence total cost in different ways. Natural gas contracts should be assessed using the appropriate regional benchmark and the customer's tolerance for price variability.
Businesses can benefit from reviewing renewal dates early, checking usage patterns and peak demand, and comparing fixed, floating and other available structures on a like-for-like basis. Multi-site organizations should avoid assuming that conditions in Alberta, Ontario, Texas or Ohio are interchangeable.
At Wholesale Energy, our focus is to put market developments into perspective, explain the choices clearly and help businesses evaluate the energy strategy that suits their operations and risk preferences.
Suggested teaser: From a major Canadian LNG expansion to tighter U.S. power markets, the third quarter highlighted why energy decisions require both a global perspective and local market knowledge.
SEO description: Q3 2026 energy market update: LNG Canada expansion, oil volatility, grid investment and electricity demand across Canada and the U.S.—and what it means for businesses.
Verification and source notes —
Coverage: July 1–September 30, 2026. Prepared October 22, 2026. Sources below are original official regulator, system-operator, agency or project-proponent publications. Forecasts, approvals, contracted capacity and operating assets are distinguished. Market observations are not advice to enter a particular energy agreement.
• EIA, September 9, 2026 — Global Oil Markets
• EIA, September 9, 2026 — Electricity Outlook
• EIA, September 9, 2026 — Natural Gas Outlook
• LNG Canada, September 28, 2026 — Phase 2 Final Investment Decision
• Alberta Energy Regulator, September 29, 2026 — Alberta Energy Outlook
• Alberta Energy Regulator, September 2026 — Natural Gas
• AESO, July 2026 — Genesee Repower Testing
• AESO — Restructured Energy Market (Transition Background)
• Government of Canada, September 29, 2026 — LNG Canada Phase 2
• Government of BC / BC Hydro, August 5, 2026 — Island Generation
• SaskPower, July 2, 2026 — International Power Line Approval
• IESO, July 17, 2026 — Capacity Auction Pre-Auction Report
• PJM, July 14, 2026 — 2028/2029 Capacity Auction Results
• ERCOT, July 8, 2026 — Large Load Batch Zero Transition
• ERCOT, September 9, 2026 — Large Load Verification
• Illinois Power Agency — 2026 Energy Storage Procurement
• Illinois Power Agency, August 17, 2026 — Draft 2027 Procurement Plan
• NYSERDA, September 23, 2026 — Storage and Renewable Contracts
• Public Utilities Commission of Ohio, September 3, 2026 — PJM Large Load Proposal
• Alberta Energy and Minerals — 2026 Natural Gas Reference Price
WHOLESALE ENERGY
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Commercial & Industrial Energy · North America
Internal test edition sent for editorial review. Not yet published online.
