BC Hydro’s draft Integrated Resources Plan and the future of energy policy in BC

Feb. 13, 2026

The utility’s plan fails to address large new sources of demand and broader climate goals

At the end of October, BC Hydro submitted its draft 2025 Integrated Resources Plan (IRP) to the BC Utilities Commission (BCUC). The IRP process involves an assessment of electricity demand forecasts for the province and new supply options to meet that demand. This exercise comes at a time when the province has big energy-related challenges, including decarbonizing transportation, buildings and industry, as well as new demand drivers from future liquefied natural gas (LNG) terminals, mining for critical minerals, and data centres for artificial intelligence operations.

The last IRP process was in 2021 and took several years, including a 2023 refresh after BC Hydro recanted its 2021 forecasts due to potential LNG loads. In the words of trade union MoveUp, BC Hydro “dramatically shifted the program from one of coasting on surplus to an urgent need for new resources.”

With the BCUC only releasing its final decision on the 2021 IRP in March 2024, BC Hydro sought to defer the 2025 IRP process but was compelled to go ahead. As a result, the draft 2025 IRP has a “dragging its feet” feel to it, and the document lacks the depth of data and analysis that usually accompany the plan. That’s a disappointment as the draft IRP does not adequately address how to meet potentially massive new sources of demand, recent years where BC has been a net importer of electricity, nor the need for the Crown corporation to play a central role in decarbonizing the provincial economy.

Electricity demand growth

My 2025 report, Painting itself into a Corner, noted that substantial new demand was coming from big resource industries who don’t expect to pay the full marginal cost of new generation and transmission. This is likely to leave other residential, commercial and light industry customers to effectively subsidize LNG and mining through higher rates. 

To make electricity pricing equivalent to using gas for an LNG operator, the price would need to be between $10 and 17 per megawatt-hour (MWh). In contrast, BC Hydro received an average of $93 per MWh in 2024. Large industrial customers paid a lot less than this, only $62 per MWh, while residential customers paid $112 per MWh. (Jargon note: one megawatt-hour (MWh) is approximately the monthly energy requirement of a typical BC home; one gigawatt-hour is 1000 MWh and is the unit used for system-wide projections.)

Unfortunately, the IRP does not include any discussion of the financial side of BC Hydro’s planning exercise, only supply and demand of electricity. Future demand in BC is anticipated in three broad areas, all of which have a high degree of uncertainty and would be competing with each other if supply growth is restricted: 

• Electrification to transition vehicles, homes and businesses off of fossil fuels 
• Big resource plays including natural gas production in the Northeast, and LNG terminals and mining in the Northwest
• Artificial intelligence and data centres, which seem to have an insatiable appetite (demand from cryptocurrency mining has been rejected) 

The 2025 IRP starts with a reference case and then considers low and high demand scenarios, the latter reflecting more resource projects going ahead, although they don’t break out exactly which ones. In addition, BC Hydro tacks on a “north coast sensitivity” exercise, but exactly how it differs from the high demand scenario is not clear, and the total future demand is in a similar ballpark. Notably, the total demand coming from the high demand scenario in the 2025 IRP is less than in the 2023 update to the last IRP (the combined accelerated electrification and North Coast LNG projections, up to 2043). 

Much depends on which projects actually go forward and whether BC remains committed to using new BC Hydro electricity to reduce emissions from energy-hungry LNG terminals. For example, Cedar LNG could require 214 MW of capacity (about 1,500 GWh per year), which requires both new generation and transmission lines. The BC government recently signed a memorandum of understanding committing to provide 600 MW of capacity for the Ksi Lisims LNG project, which has not yet reached a final investment decision. This works out to about 5,000 GWh per year, but it is not clear how this fits in with the IRP framework. Additional demand from LNG alone could easily overwhelm the high scenario in the IRP. 

Nor does the IRP explicitly plan for new demand from data centres and artificial intelligence. At the end of January, the BC government announced that a competitive process in 2026 would be used to allocate 400 MW to this end (300 MW for AI, 100 MW for data centres), which works out to another 3,000 GWh, equivalent to five per cent of current supply. In contrast, BC Hydro will continue to try to accommodate big resource projects. The BC government appears to be far ahead of BC Hydro’s planning processes in the IRP, and the utility is now playing catch up.

The BC Utilities Commission clearly needs to press BC Hydro for more detailed planning data underpinning various scenarios, and if push comes to shove, whether the utility would entertain dirtier sources of power to provide the capacity demanded by industry. Several LNG and mining projects have been deemed major projects in the national interest, intertwined with Canada’s response to the Trump administration’s trade policies. Interest in data centres and artificial intelligence is very high but little planning work has been done about what electricity supply might be available or what are the trade offs with other uses.

Supply and demand framework

Figure 1 shows supply and demand projections based on the IRP. The reference and high demand cases are shown as lines (the low case is ignored for now given the abundant demand pressures discussed above). BC Hydro’s reference demand from homes, businesses and larger industry will be just over 61,000 GWh in 2026, rising to more than 83,500 GWh by 2050, whereas the high demand scenario goes to more than 91,000 GWh by 2050. Both of these cases are reduced by planned conservation (or demand side management) measures, which grow to a reduction in demand of about 8,400 GWh in 2050.

The stacked bars show supply, including base supply (hydroelectric dams including the new Site C dam), electricity purchase agreements for private power (originally from the 2010s), and the 2024 and 2025 calls for private power. For the 2024 and 2025 calls for power, official news releases state 10 projects yielding 4,830 gigawatt-hours (GWh) per year from the 2024 call and 14 projects and 9,100 GWh per year from the 2025 call. These are assumed to be phased in up to 2035, at a rate of 85 per cent to reflect that certain projects may not go ahead or produce as much electricity as planned.

On the plus side, BC Hydro’s assessment is that the province has abundant, untapped electricity resources. The IRP presents supply cost curves for various renewable options and suggests that BC could develop about 80,000 GWh of utility-scale solar and on- and off-shore wind generation, all up to a cost of $100 per MWh. Getting these resources online can take up to 10 years, and all new projects have an environmental footprint, but that renewable power is available should we choose to develop it. 

One challenge is the province’s new reliance on buying power from private producers, and locking them into long-term contracts, rather than simply building these generation assets through BC Hydro itself. The 2024 and 2025 calls for power were notable for their requirement of equity partnerships with BC First Nations, and this would need to be the case for future calls as well. However, concerns exist about who is financing these deals and potential downsides if demand does not materialize as planned. 

To connect new sources of supply and demand, a planned $6 billion North Coast Transmission Line (NCTL) will connect new electricity supply to LNG and mining operations in the Northwest of BC. The NCTL is on the federal major projects list and is being fast-tracked by the province and BC Hydro, including absenting it from review by the BC Utilities Commission. In light of the massive cost over-runs associated with the Site C dam, this could be problematic, as the cost of the NCTL has already been increased from $3 billion originally.

In addition to total electricity generation (on an annual basis) is the maximum capacity for the overall BC Hydro system, which is designed to handle a peak load representing the early evening of a cold winter day. Baseload electricity matters and is more valuable, whereas some supply options, like solar or run-of-the-river hydro, can generate power but do not necessarily provide that capacity when it’s needed most. That said, increasingly, reliability comes from different resources working together, and innovations in storage and batteries can shore up the capacity of renewable electricity resources.

Peak demand in 2025 was 11,100 megawatts (MW) and the IRP estimates it could rise to 15,100 MW by 2050 in the reference case and 16,300 MW in the high demand case, plus an additional 900 MW for LNG, mining and more under the North Coast load sensitivity. Again, precisely what goes into these scenarios is not transparent but the bottom line is clear: substantial new investments in generation and transmission will be needed. The capacity of the massive new Site C dam is 1,100 MW, so BC is looking at the equivalent of four to six Site C dams needed to bridge this gap.

Conservation (also known as demand-side management or DSM) is another pathway to meeting both generation and capacity targets. Such measures generally cost much less than acquiring new power, and include pricing and time-shifting incentives like getting people’s electric cars charged in the middle of the night or whenever renewable resources are plentiful. While a base level of DSM is included in the IRP, more aggressive measures could be contemplated that would further reduce the need for additional supply.

Finally, the IRP barely touches on imports and exports of electricity. Historically, BC Hydro has had an electricity surplus that it exported to the United States, while also being able to profit from arbitrage, or importing power when electricity was cheap and selling it as exported power when expensive. Low water levels amid increased drought in recent years have altered this equation. In 2024, BC Hydro had net imports of 13,600 GWh, almost one-quarter of power sales. In 2025 that deficit is projected to about half as large, and after 2026 it is projected to return to surplus electricity. 

BC Hydro spent about $1.8 billion on electricity imports net of exports in 2024 and 2025. If the recent drought is not a temporary phenomenon, and more of an indicator of a new normal, BC Hydro’s planning framework could be subject to regular years when the province does not produce enough electricity to meet committed demand, and would have to import power at market prices.

What happened to climate action?

The IRP proceedings at the BC Utilities Commission are continuing through Spring 2026. As intervenors make comments and the commission asks for additional information, greater clarity from BC Hydro may emerge about whether it is serious about meeting the potentially massive increase in demand from big resource industries, data centres and electrification of the domestic economy. 

It is widely believed that electrification of the economy, as quickly as possible, is a key part of climate action in BC. Reducing greenhouse gas emissions and long-term sustainability require substantial new investments in clean electricity supply. Unfortunately, the IRP balks at making any projections based on the province meeting its GHG targets. It’s unfortunate that climate considerations have not been explicitly part of this exercise.

Whether we choose to ignore it or not, climate change is already affecting the electricity generation side. Future drought due to climate change could greatly undermine the available power supply from BC Hydro’s legacy dams. Additional transmission infrastructure could be also considered with expanded electricity cooperation via new interties with Alberta, Yukon and Northwestern states. This could improve system management and resilience of all jurisdictions.

A planning document that does not plan for BC meeting its legislated GHG targets is not a complete plan. A truly integrated approach to BC electricity is needed given multiple objectives and potentially large affordability impacts on BC households and businesses. BC Hydro should be sent back to the drawing board and required to do more detailed scenario planning before the BCUC approves its 2025 IRP.