The Grid Is Under More Pressure Than You Are Being Told

Four consecutive Emergency Energy Alerts in January 2024. The first firm load shed in Alberta since 2013, on April 5, 2024, when thermal generator failures collided with high demand and insufficient wind. Thirteen grid alerts issued over last winter. These are not anomalies from a system undergoing a one-time stress test. They are the early data points of a grid running out of margin, and the trend is not improving.

The most severe alert category (an EEA-3, meaning Alberta is at genuine risk of rotating blackouts) occurred seven times in 2022, four times in 2023, and six times in 2024. The cause that dominated media coverage was renewable intermittency. The cause that actually drove most of those alerts was less politically convenient: unplanned outages at natural gas generation facilities. Several major gas plants failed simultaneously during extreme cold events, at exactly the moment demand peaked. Solar and wind did not cause the January 2024 crisis. Frozen gas generators did.

On the distribution side, FortisAlberta’s own reliability data tells the rural story plainly. In 2022, the provincial average for outage duration was 1.70 hours per customer per year, across an average of 1.08 interruptions. That is the mean. Rural customers at the end of long distribution lines (the acreage owners, farm operators, and small commercial properties that make up most of this territory) experience substantially more. Electrification of transportation and heating is adding load to a distribution system built for a different consumption profile. A 25-year infrastructure decision made today should account for the grid of 2035, not the grid of 2015.

Storage Is Not One Product

The term battery backup covers a range of systems with fundamentally different capabilities, price points, and financial logic. Before evaluating any of them, it helps to understand what category of problem each one is designed to solve.

There are three meaningful tiers in the Alberta residential and small-commercial market. The first protects critical loads during an outage and reduces your bill modestly. The second provides whole-home backup, meaningful bill elimination, and Solar Club financial returns when properly integrated with solar. The third delivers complete grid independence for properties where a connection is prohibitively expensive or simply not wanted. Each tier has a legitimate use case. None of them is universally right.

Critical loads backup. Around $35,000.

PV, battery, and a critical loads panel. For an existing home where resilience matters more than bill elimination.

Whole-home all-in-one. $54,000.

16 kW solar, 20 kWh storage, and the Hub G2. For a new build on Solar Club aiming to eliminate the bill.

Off-grid. $177,000.

32 kW solar, 80 kWh storage, and a 26 kW Briggs and Stratton generator. For a remote property where a grid connection is prohibitively expensive.

Tier One: Critical Loads Backup

A critical loads backup system does one job well: it keeps your essential circuits running when the grid goes down. The architecture is straightforward. A sub-panel, called a critical loads panel, is wired to carry only the circuits that matter most: refrigerator, well pump, furnace fan, lighting, and basic communications. A transfer switch, either manual or automatic, disconnects that sub-panel from the grid during an outage and connects it to the battery inverter. The rest of the home goes dark, but the things that matter keep running.

For an existing home where resilience rather than bill elimination is the priority, this is often the right answer. You are adding a parallel path for essential loads rather than replacing your electrical service infrastructure. The installation footprint is smaller, the permitting is simpler, and the investment is considerably lower. The trade-off is that without a properly integrated solar array and full energy management system, the bill savings are incremental rather than transformative. This tier makes sense as a resilience investment. It is not primarily a financial one.

Installed cost: approximately $35,000 including PV and battery.

Tier Two: The Whole-Home All-in-One System

This is the system that changes the economics of owning property in Alberta. The architecture has three hardware components that work as a unit: a hybrid inverter, a battery stack, and an energy management hub. Understanding what each does, and especially why the hub is the component most people do not know exists, is essential before evaluating whether this system makes sense.

The hybrid inverter handles two jobs simultaneously. It converts DC power from the solar panels into usable AC for your home and the grid, managing multiple independent strings of panels through dedicated MPPT inputs. At the same time it manages the battery, charging from solar surplus or from the grid on command and discharging to home loads as needed. This single device replaces what would otherwise require a separate string inverter and a separate battery inverter, two devices, two installation footprints, two sets of communications.

The battery stack uses lithium iron phosphate chemistry, the same chemistry used in most serious residential storage for its safety profile and longevity. Standard configuration for a new build delivers 20 kWh of usable storage. The battery includes internal warming rated to -25 Celsius. In Alberta that specification is not a footnote. A battery that shuts down at -30 is useless precisely when you need it most. Storage capacity scales in modules from 20 kWh in a standard installation up to 80 kWh across four inverter units for large properties or off-grid applications.

The Energy Hub: The Component That Makes It Coherent

The energy management hub is what separates a whole-home all-in-one system from a solar installation with a battery bolted on. In the Fox ESS system, which uses the same architecture as the Canadian Solar EP Cube, this component is called the Fox Hub G2. The hub has five distinct connection terminals: backup load output, non-backup load output, grid connection, solar and inverter input, and generator input. When the grid is operating normally, the hub manages all energy flows in real time, routing solar production to home loads, battery, or grid export based on configured priorities. When the grid fails, the hub detects the outage in under 20 milliseconds and switches seamlessly to island mode. The transition is fast enough that clocks do not reset and computers do not notice.

Several capabilities the hub provides are worth naming specifically, because they are not obvious from looking at the equipment. First, the hub provides a 200-amp busbar that becomes the new electrical centre of the home. An existing 100-amp panel that is already heavily loaded cannot easily absorb the complexity of a full storage system. The hub replaces the service centre rather than adding to it. The existing panel becomes the backup load sub-panel, fully protected by the system. Second, a dedicated generator terminal with a dry-contact auto-start circuit means a standby generator starts automatically when the battery drops below a configured reserve threshold. No manual intervention required during a multi-day outage. Third, full consumption monitoring in addition to production monitoring gives you genuine site-level data rather than just solar generation numbers. You can see exactly where your energy goes. Fourth, a configurable backup reserve lets you designate a percentage of battery capacity for outage coverage while deploying the remainder for Solar Club load shifting. Fifth, dedicated EV and large appliance circuits allow an electric vehicle charger to draw directly from solar production, reducing or eliminating grid interaction for EV charging entirely.

The hub is not an optional add-on. It is the component that makes the rest of the system coherent. Without it, you have solar and a battery. With it, you have a managed energy system.

There is also an upgrade path worth naming. We frequently install the hybrid inverter alone for customers who want solar today but are not ready for the full storage investment. The inverter uses identical architecture to the all-in-one system. When the customer decides to add storage, the battery stack and hub connect to the existing inverter with minimal additional work. The infrastructure decision is made once. The financial decision is phased.

Installed cost (16 kW solar, 20 kWh storage): $54,000.

The Financial Case: Real Customers, Real Bills

The financial argument for the whole-home system rests on three things working together: the right solar array size, the right rate structure, and a system that manages both intelligently. The following draws on actual billing data from two Boreal Energy customers on Park Power’s Solar Club program to show what that looks like in practice.

The first customer (Greg, on an acreage property in Parkland County with two electric vehicles and a year-round hot tub) consumed 13,400 kWh through the system in 2025 and ended the year with a credit balance of $1,335 from his electricity retailer. He made no electricity payments from April onward. The credit carryforward covered his subsequent winter bills, and Park Power issued a direct deposit to his bank account in spring 2026. The second customer (Jonathan, a Strathcona County property) received a $206.29 direct deposit to his bank account in November 2025, triggered automatically after his credit balance exceeded the Solar Club payout threshold for two consecutive months. These are not modelled projections. They are documented on utility billing records that Boreal has reviewed.

The rate structure that makes this work is Solar Club, offered by Park Power and available to microgenerators on FortisAlberta’s distribution territory. Customers on Solar Club earn 30 cents per kilowatt-hour for energy exported to the grid. When importing, they pay their chosen commodity rate, currently as low as 7.99 cents per kilowatt-hour on a fixed plan, plus transmission and distribution charges that bring the all-in import cost to roughly 15 to 16 cents per kilowatt-hour. The export credit covers energy only. Transmission and distribution do not apply to exports. This asymmetry is structural and permanent on Solar Club, regardless of which commodity rate product the customer chooses. Every kilowatt-hour the system self-consumes, whether directly from solar or dispatched from the battery, is worth the full import rate including T&D. Every kilowatt-hour exported is worth the energy commodity rate only.

The practical strategy is straightforward. Export as much solar as possible during the high-value season on the variable Solar Club product, where the commodity rate tracks the Alberta market and earns 30 cents per kilowatt-hour in credit. Switch to a low fixed rate for the winter import season, paying 7.99 cents for the grid power the system cannot cover. The battery extends the solar day into evening hours, reducing imports during the production season and increasing the volume of generation that earns the full export credit. Solar Club allows customers to switch between rate products at any time. That flexibility is a deliberate feature of the product design, and it is part of what makes the seasonal strategy executable.

The honest caveat belongs here. The battery’s incremental financial contribution, isolated from the solar array on a flat-rate structure, is modest. The transmission and distribution spread captured by self-consuming through the battery rather than exporting and later reimporting runs to approximately $200 to $400 per year on a 20 kWh system at current rates. The battery earns its place in the financial case as part of the integrated system, not as a standalone investment. On a new build where the hub and inverter infrastructure are costs you are incurring regardless of whether storage is added, the incremental cost of the battery component is the right comparison, and that comparison is considerably more favourable than evaluating the full system cost against battery savings alone.

Adding Storage to a System You Already Own

A large share of Alberta homes already have solar. The common question from those owners is whether a battery can be added to an array that is already on the roof or in the yard, and the answer is yes, though the right method is not always the obvious one.

The approach that works best is to install a complete hybrid battery system (a full EP Cube or Fox ESS with its energy hub) alongside the existing array rather than replacing the existing inverters. The original solar stays in place on its own string or microinverters and is wired into the hub as AC-coupled solar, where it is monitored in the app alongside everything else.

The advantage of this method is not obvious until the grid goes down. A conventional grid-tied solar system is required by anti-islanding rules to shut off the moment it loses the grid. On a clear day during an outage, a standard array produces nothing, and the homeowner sits under a full roof of panels with no power. A hybrid battery system is grid-forming. During an outage it creates its own stable AC reference, and the existing grid-tied inverters detect that reference and continue operating as though the grid were still present. The array that would otherwise be dead weight in a blackout now runs the home and recharges the battery in daylight. The hub manages that production, directing it to loads and battery and throttling it when the battery is full.

The honest trade-off is cost. A hybrid inverter sized to manage the battery is being purchased without any new DC solar connected to its own inputs, so the owner is paying for conversion capacity that is not fully used on day one. What that cost buys is real: outage resilience for an array that previously had none, a clean path to expand with DC-coupled panels later without a second infrastructure project, and the ability to configure the system for zero export so that production is prioritized for self-consumption and battery charging rather than sold back at the export rate. On Solar Club, where self-consumed energy is worth the full import rate including transmission and distribution while exports earn the commodity rate only, that self-consumption bias is worth more than it first appears.

A storage retrofit on an existing array is best understood the same way a critical loads system is. Resilience is the primary return, and the financial case follows from self-consumption rather than from the battery in isolation.

Tier Three: Off-Grid, When Full Independence Makes Sense

Full off-grid operation is the most expensive configuration and the right answer for a narrower set of situations than marketing materials suggest. A properly specified off-grid system for a large Alberta acreage costs $177,000. That includes 32 kilowatts of solar on ground arrays, 80 kWh of battery storage across four inverter units, and a 26-kilowatt Briggs and Stratton standby generator. The generator is not optional, and understanding why requires doing the Alberta winter math honestly.

In December and January, central Alberta averages three to four peak sun hours per day under clear conditions. A 32-kilowatt system at three peak hours generates roughly 96 kWh on a good day. An off-grid property with a well pump, electric heat backup, standard appliances, and lighting typically uses 30 to 50 kWh per day in winter. On a clear day the system covers it. During a four-day cloudy stretch, common in Alberta winters, daily solar production can drop to 20 kWh or less. At 40 kWh of daily consumption and 20 kWh of production, you are drawing 20 kWh per day from the battery. Eighty kilowatt-hours of storage buys four days before the generator must run. The generator charges the battery and carries the loads simultaneously, bridging the solar deficit until conditions improve. It is not a luxury item in the specification. It is the winter backup for the winter backup.

The economics of off-grid make sense in two specific circumstances. The first is a rural property where the cost of extending grid service (poles, trenching, transformer upgrades, utility connection fees) approaches or exceeds the cost of the off-grid system itself. In Sturgeon County and the broader territory where Boreal works, a new service connection requiring 400 metres of pole line and distribution upgrades can run $80,000 to $150,000 before the first kilowatt-hour is delivered. Against that baseline, $177,000 for a complete energy system that also eliminates the ongoing electricity bill is a different calculation entirely. The second circumstance is a customer for whom grid independence has intrinsic value that does not appear in a payback spreadsheet: a working farm where a multi-hour outage means lost production, or a property owner who has watched FortisAlberta’s rural reliability data accumulate and decided that grid dependency is an operational risk they no longer want to carry.

Arbitrage and the Rate Structure That Is Coming

Time-of-use pricing does not currently exist for residential customers in Alberta, with one exception: a small pilot program in Grande Prairie run by ATCO Electric. For the vast majority of Alberta households, electricity is sold at a flat commodity rate regardless of when it is consumed. That is changing, and the timeline is no longer speculative.

In June 2025, the Alberta Utilities Commission published Bulletin 2025-07, initiating a formal engagement on enabling time-varying rates for residential and small commercial customers. The AUC’s own analysis concluded that the expected benefits of enabling these rates will outweigh the expected costs by orders of magnitude. That conclusion was not challenged by FortisAlberta, EPCOR, ATCO, or the AESO in their formal submissions. An implementation engagement ran through October and November 2025. The AESO is separately targeting five-minute settlement intervals for all loads by 2032. Broad residential TOU rollout is likely to arrive somewhere between 2028 and 2030.

Arbitrage, in the context of storage, means charging the battery when electricity is cheap and discharging when it is expensive: buying low, selling high, capturing the spread. The advantage scales directly with that spread. Ontario’s Ultralow Overnight rate runs from 3.9 cents per kilowatt-hour overnight to 39.1 cents at weekday peak, a spread large enough to make battery arbitrage the dominant use case for storage, independent of solar entirely. In California under the current Net Billing Tariff, the combination of low export rates and high time-of-use import rates makes battery storage financially compelling even without strong solar economics to anchor the system.

The Solar Club rate-switching strategy that Boreal customers are already executing is an early and manual form of this arbitrage. Export at 30 cents during the high-value season. Import at 7.99 cents during winter. When TOU rates arrive in Alberta and interval meters become standard, this optimization moves from a manual retailer decision to an automated system function. Battery systems installed today will be capable of participating in that market without hardware replacement.

Vehicle-to-Grid: The Technology Canada Has Not Unlocked Yet

The concept is compelling. An electric vehicle’s battery holds 60 to 100 kilowatt-hours of storage, three to five times the capacity of a standard residential battery system, at a cost already justified by transportation rather than energy storage. If that battery can move energy bidirectionally, the economics of residential storage change fundamentally. The technology exists. The regulations do not.

There are three distinct versions of this capability worth distinguishing. Vehicle-to-load means an EV with a power export port can directly power appliances through a standard outlet built into the vehicle. Several current vehicles including the Ford F-150 Lightning and certain GM trucks offer this today. No regulatory approval is required. It is useful for a jobsite or a camping setup but is not a meaningful home backup solution. Vehicle-to-home requires a separate bidirectional inverter installed between the vehicle and the home’s electrical system. This is where the regulatory gap becomes concrete. As of mid-2024, no CSA-approved bidirectional EV charger was commercially available for residential installation in Canada. The equipment category did not yet have the certification pathway needed for a licensed electrical contractor to install and permit it. Vehicle-to-grid, where the EV dispatches energy back to the distribution grid as an active market participant, requires all of the above plus utility-level interconnection agreements and a regulatory framework that does not yet exist in Alberta.

The practical timeline for residential vehicle-to-home in Alberta is probably 2027 to 2029, depending on how quickly CSA certification processes move and how aggressively utilities and regulators engage on interconnection standards. Energy management hubs like the Fox Hub G2 already include dedicated EV charging circuits. Customers installing these systems today are building infrastructure that will be compatible with bidirectional EV capability when the regulatory pathway opens.

Virtual Power Plants: Alberta’s Unexpected Competitive Edge

A virtual power plant is not a physical facility. It is software that aggregates the storage capacity of distributed residential batteries and dispatches them as a coordinated resource, charging when grid power is abundant and cheap, discharging when demand peaks and prices spike. From the electricity market’s perspective, a virtual power plant looks like a conventional generator. From the homeowner’s perspective, it is a program that optimizes the financial return on their storage investment while providing a grid stabilization service they are compensated for.

Alberta is the only Canadian province where a true commercial residential virtual power plant currently operates. The structural reason is Alberta’s deregulated electricity market, which gives licensed retailers direct access to wholesale prices and the ability to bid distributed resources into the market as actual participants. In regulated provinces this pathway does not exist without direct utility involvement. Solartility, a Calgary-based electricity retailer, operates Alberta’s first retail virtual power plant by connecting homes with solar, storage, and bidirectional interval meters into a software-managed pool. The system optimizes export pricing across the aggregate and minimizes import costs, with customers accessing wholesale electricity prices rather than flat retail rates, potential savings the company describes as up to 30 percent on electricity costs.

The physical instantiation of this at community scale arrived in Edmonton in June 2025. Blatchford Lands, a net-zero master-planned community on the site of the former municipal airport, launched a virtual power plant involving 100 sonnen home batteries representing approximately 500 kilowatts of power and more than 2 megawatt-hours of storage. The project involves EPCOR as the distribution utility, Solartility as the retail electricity manager, Landmark Homes as the builder, and Emissions Reduction Alberta with $3.3 million in program funding. Each home carries 5 kilowatts of solar and a 20 kilowatt-hour battery cabinet. EPCOR and Solartility can draw from the aggregated battery pool to stabilize local grid conditions or respond to high-demand events. Homeowners retain full backup power capability throughout. This is operating infrastructure in Edmonton right now.

When the AUC’s time-varying rate implementation arrives and interval metering becomes standard, the economics of VPP participation will improve further. Residential storage installed in 2025 and 2026 will be eligible to participate in that market without hardware replacement. The equipment decisions made today are not just about today’s electricity bill.

The Honest Assessment

Energy storage in Alberta is not one thing and the financial case is not the same across all configurations. A critical loads backup system on an existing home is a resilience investment that stands on its own terms. A whole-home solar-plus-storage system on Solar Club delivers documented bill elimination and direct deposits to bank accounts (the billing records from two customers across twelve months confirm it), but the financial case requires the right rate structure and proper system integration, not just a battery. Off-grid makes economic sense for specific rural properties where the grid connection baseline changes the calculation entirely.

The battery’s standalone financial contribution at current flat rates is modest. The spread captured by self-consuming through storage rather than exporting and reimporting runs to a few hundred dollars per year on a 20 kWh system. The financial case lives in the integrated system: solar plus storage plus Solar Club rate management, on a new build where the hub and inverter infrastructure are unavoidable costs regardless of whether storage is added. On those terms the case is real, supported by documented customer outcomes, and conservative relative to the rate environment that is coming.

The grid is under pressure. The rate structure is changing. The technology is proven. The question is not whether to engage with storage. It is which tier fits your situation, at what cost, and on what timeline.

Jordan Forsythe is the owner of Boreal Energy Solutions Inc. and the publisher of Boreal Dispatch.

Billing data referenced is from consented customers on FortisAlberta’s distribution system, Park Power Solar Club rate product. System pricing reflects Boreal Energy Solutions retail rates as of 2026.

Peak shaving is the most over-promised and under-delivered concept in Alberta commercial energy. Every solar installer with a battery datasheet talks about it. Every utility presentation has a slide on it. Every economic-development pitch deck for an industrial park name-drops it. Walk an industrial yard in central Alberta and count the battery rooms that are actually doing it well, and you will not need both hands.

I am telling you that for most commercial customers, solar on its own is a mediocre investment. The economics that actually move are not in the kilowatt-hours your panels offset. They are in the kilowatts of peak demand you can engineer out of your bill, and the rate class you can migrate yourself into once you have done it. That is the part the industry does not sell, because doing it requires three technologies working together and the discipline to integrate them. Most installers cannot, so they do not.

If you run a commercial or industrial site in Alberta and you have ever opened your invoice and wondered why the numbers do not move much when you turn things off, this is for you.

Your bill is not about how much. It is about when.

Pull a recent commercial invoice from any Alberta distributor. The energy charge, the part that scales with kilowatt-hours, is not where most of your money is going. The money is in the System Usage Charge, which on the standard mid-tier commercial rate in 2026 sits at roughly $0.245 per kW-day for transmission and $0.108 per kW-day for distribution. Combined, you are paying around $10.59 per kW per month, billed against the highest fifteen-minute interval the meter recorded in the period.

Read that again. One fifteen-minute window sets the bill. Not your average load. Not your monthly consumption. The single worst quarter-hour of the month. If your compressor staged up at the same time your block heaters cycled on at the same time your wash bay started its rinse, you just paid for that on every kilowatt above your previous peak. And on the standard commercial tier, there is a 50 kW rate minimum floor underneath you, so the savings only count once you push the peak below it.

Move up to the next tier, the rate that applies to sites with expected peak capacity over 2,000 kW, and the structure is meaner. The rate minimum is 2,000 kW. The capacity charge is calculated on the greater of metered peak or 135 percent of your Contract Minimum Demand. And the ratchet runs at 85 percent of your trailing 12-month peak. That means one bad month in February drags your bill floor along behind you for the next eleven, regardless of what you actually use. The ratchet is the bear trap, and it is set.

When your installer shows you a payback period built on kilowatt-hour offset, they are showing you the smaller of the two numbers on your bill. The larger one is still sitting there, untouched, every month for the life of the system.

Solar alone reduces the wrong number

Photovoltaic panels produce power when the sun is up. That is a tautology, but it is the part the commercial pitch deck skates past. Commercial peaks frequently do not align with solar peaks. The 7am startup pulse, when motors and air handlers and compressors all stage on within minutes of each other, happens before the array has woken up. The January block-heater season runs on a sun angle that gives you maybe four useful production hours per day. A cloudy Tuesday in November can drag a 200 kW array down to 20 kW for the exact afternoon your peak lands.

Solar reliably reduces the energy charge. It reduces the demand charge only when the weather and the load curve agree to cooperate, which on the worst day of the month they will not. The customer who installs solar alone has bought a partial hedge against the smaller line on the bill and zero hedge against the larger one. The system still pays back. It just pays back on the easy money, while the hard money goes uncollected.

This is why a residential installer porting their playbook directly into commercial gets the answer wrong. Residential rates are flat per kilowatt-hour. Commercial rates are not. The tool that works on a house does not work on a parts shop, and the spreadsheet that produced the residential payback period is solving a different equation than the one the customer is actually being billed against.

The battery is not the answer either, unless you size it to the load

Here is where the industry goes wrong in the other direction. Once people figure out that demand charges are the problem, the next pitch is a battery sized to flatten the whole site’s peak. Take the worst quarter-hour of the year, subtract whatever target peak you want, and quote a battery big enough to discharge that delta for fifteen minutes. The math works on paper. The capex does not.

A site running a 55 kW peak does not need a 55 kWh battery. It needs a battery sized to cover the specific discrete loads that are driving the peak, installed at the main service so it can defend the metered total against whatever combination of those loads cycles on at the worst moment. The sizing exercise is not how big to make the battery. The sizing exercise is which loads to engineer against and how much capacity each one demands.

I am designing a system right now for an Alberta dealer running a 55 kW monthly peak on the mid-tier commercial rate. About 15 kW of that peak comes from a heavy industrial parts washer on its heating and pump cycle. The rest comes from a handful of other discrete loads with their own startup signatures, each contributing somewhere between three and eight kilowatts when they fire. The target is to bring the metered peak down by at least 25 kilowatts and hold it there reliably.

Twenty-five kilowatts of reduction matters because it changes the rate class. At 55 kW the customer is in the standard commercial tier, paying against a 50 kW rate minimum and the higher per-kW-day System Usage Charge. At a peak under 35 kW the customer qualifies for the small-commercial tier, where the rate minimum is 3 kW and the structure is built for a fundamentally smaller customer. The energy still flows behind the meter at the same volume. The bill structure changes. That is the actual prize.

The battery for this site is a 100 kWh lithium iron phosphate unit on a 100 kW inverter, installed at the main service. It is not dedicated to any one piece of equipment. It is sized to the load profile, governed by a controller that has to recognize which combination of equipment is actually about to push the meter over the ceiling and discharge accordingly. A battery this size without the controller would either over-discharge on irrelevant load spikes and run out of capacity when the real peak landed, or sit idle until the meter had already gone over. The controller is what makes the same hardware do the rate-migration job.

Peak shaving and load displacement are not the same thing

In the industry, peak shaving has become shorthand for everything a battery does to reduce a commercial bill. That is sloppy. There are two distinct strategies, and they are in tension with each other.

Load displacement is the strategy of capturing excess solar production into the battery during the day and discharging it after the panels stop producing, to reduce the volume of energy bought from the grid in the evening. It targets the energy charge, the kilowatt-hours. It wants the battery as empty as possible by sundown so it has room to absorb tomorrow’s solar.

Peak shaving is the strategy of holding charge in reserve so the battery can discharge against a defined demand ceiling whenever the site looks like it is going to exceed it. It targets the demand charge, the kilowatts. It wants the battery as full as possible at all times so it has ammunition to defend the threshold.

These two strategies want opposite things from the battery’s state of charge. A battery doing load displacement is empty in the evening. A battery doing peak shaving is full in the evening. Most commercial installs pick one of the two strategies, set the inverter to do it, and stop there. The customer gets either the energy savings or the demand savings, not both. That is what the industry usually delivers when it says peak shaving, and the customer rarely knows the other half of the value is sitting on the table.

The controller is the part nobody mentions

A battery on its own is a dumb buffer. It will discharge when you tell it to and recharge when you let it. What it cannot do, unaided, is decide intelligently against a moving target. It does not know your demand ceiling. It does not know whether tomorrow’s forecast supports holding charge in reserve or spending it tonight. It does not know whether the load profile shifted last quarter when the customer added new equipment. It executes whatever inverter set-point the installer programmed at commissioning, and it does that forever, regardless of whether the set-point is still right.

That is the failure mode the industry skates past. Most commercial battery installs use manually-set deployment thresholds. The threshold has to be set conservatively, because it has to protect against the worst possible month of the year, which means for the other eleven months the battery is leaving seasonal savings on the floor. And when the customer adds a new piece of equipment that changes the load profile, nobody updates the threshold. The inverter keeps doing what it was told to do in 2024 while the bill creeps back up in 2026. There is no installer making house calls to retune set-points. The site is set, and the set is wrong.

That is what a microgrid controller does differently. The system I deploy for this kind of work, the Sponge controller, sits across the inverters and batteries and adjusts the set-points continuously. It generates production and consumption forecasts on a rolling basis and updates inverter targets every few minutes against the current rate structure, the current load profile, and the weather it expects in the next 24 to 48 hours. When the customer adds new equipment, the controller recognizes the shift in the load curve and adapts. There is no manual retune required, because there is no fixed threshold to retune.

More importantly, Sponge runs load displacement and peak shaving as a single combined strategy, not as a choice between them. It decides, hour by hour, how much of the battery’s capacity to allocate to defending tomorrow’s demand ceiling versus absorbing today’s surplus solar. On a comparable commercial customer where this kind of system has been deployed long enough to measure, the dual strategy produces roughly 27 percent more annual savings than the better of the two single-strategy approaches. That gap is not a small efficiency. That is the difference between a project that pays back and a project that pays back well.

Sponge does not, on its own, shed loads. It does not turn off the HVAC or sequence compressor starts. That is a separate layer, and a fair question to ask any installer pitching peak shaving is whether their proposal addresses load shedding at all, and if so, with what equipment. For most commercial sites the answer is that they do not need full load-side demand response. A correctly sized battery at the main service, governed by a controller that runs both strategies simultaneously, handles the majority of the peak-management problem on its own. Load shedding becomes the optional fourth layer for sites whose load profile genuinely demands it.

One more thing worth knowing about this class of controller, because no panel-and-battery installer will mention it: Sponge runs a counterfactual simulation in parallel with the live control loop. The simulation models what the system would have done under baseline controls and compares it to what the controller actually did. That comparison is exportable. The customer can see, in dollars, what the controller is contributing month over month. Most commercial battery installs cannot prove they are doing anything. This one can.

The rate-migration play

The Alberta distribution rate schedules have multiple tiers, and the tier you sit in is determined by your expected peak capacity. On the 2026 schedules, the small-commercial tier applies to sites with expected peak under 75 kW. The combined System Usage Charge is roughly $0.308 per kW-day. The rate minimum is 3 kW, not 50. And the ratchet runs at 85 percent of your trailing 12-month peak, less a 50 kW carve-out. That carve-out is the door. It is what makes migration into the small-commercial tier viable for a customer who used to run hot enough to be billed under the mid-tier rate.

If you can hold your metered peak under 35 kW reliably, you are no longer a mid-tier customer. You exit the 50 kW floor, the higher per-kW-day distribution charge, and the ratchet that follows you for a year on bad months. You move into a rate class designed for a fundamentally smaller customer, while doing the same volume of business behind the meter. The energy still flows. The bill structure changes.

No customer is going to commit to a 35 kW ceiling on a handshake. They will commit to it when there is a battery sized to cover the specific equipment that would otherwise push them over, a controller that adapts to seasonal load shifts without manual intervention, and a counterfactual log proving in dollars that the ceiling has held. That is what makes the migration bankable. Without the stack, the customer has to leave the demand-charge savings on the table because there is no engineered way to guarantee the ceiling. With the stack, the savings become a line item.

The mid-tier to small-commercial migration is, for the right site, the single largest economic lever on the bill. It is the thing the three-layer stack actually unlocks, and it is the answer to why the math on panels alone never quite gets there. It is also the part of the analysis the panels-only installer cannot present, because the conversation requires reading the tariff.

The federal stack does the rest

Net capital on a three-layer system looks heavier than it ends up being. The 30 percent Clean Technology Investment Tax Credit is refundable, which means a corporation in a non-taxable position receives it as cash, not as a future tax shield. Class 43.2 accelerated capital cost allowance lets the depreciation run on a half-year-rule basis at 30 percent declining balance, which compresses the tax shield into the years when the customer is paying the financing. SREPs streams add a layer on top for qualifying projects.

Stack those against the demand-charge savings and the rate-migration savings, not the energy-charge savings, and the payback period compares well to most capital projects a CFO is already approving. It compares particularly well to projects whose return is denominated in avoided risk rather than positive cash flow, which is the category most operational capex falls into. A demand-side system is an unusual capital project in that respect. It pays back on cash that was being spent and now is not, which is the easiest kind of return to defend to a board.

The honest summary

Peak shaving is talked about constantly because it sounds simple and the brochures are easy to print. It is done well rarely because doing it well requires interval-data analysis, equipment-specific load mapping, a correctly sized battery installed at the main service, a controller that runs load displacement and peak shaving as a combined strategy and adapts the set-points without manual intervention, and an installer who has actually read the tariff the customer is being billed under. Most projects skip one or more of those steps. The result is a system that delivers on the energy side and misses on the demand side, which is to say, delivers on the smaller number and misses on the larger one.

If you are looking at a commercial solar proposal right now, the question to ask is not how much energy the array will offset. It is what the proposal does, specifically, to the peak kW number on your invoice, what evidence the installer has that the design will hold that peak under a defined ceiling, and whether the controller will still be doing the right thing in three years when your load profile has shifted. If they cannot answer those questions, they are selling you the easy half of the problem and leaving the expensive half on the meter.

There is real money on this. There are very few people doing it well. Both of those facts are true at the same time, and they are not going to stay that way forever.

Jordan Forsythe owns Boreal Energy Solutions, a residential and commercial solar and storage installer working across Alberta. Boreal Dispatch is his independent newsletter on Alberta’s energy economy

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Part One of this series, Bootleggers and Baptists, described a carbon pricing system that exists not to reduce emissions but to serve the political and financial interests of the parties that depend on it. The Liberals use it to claim climate action. The Conservatives use it as a grievance. The institutional investors who own the credit-generating assets need it to protect the value of their holdings. And the net atmospheric result of more solar generation entering that system is cheaper industrial compliance, not cleaner air. If you have not read Part One, start there. What follows is a concrete Alberta example of everything it described.

I have skin in this game and you should know exactly what kind. I run a residential and commercial solar installation company. Sturgeon County is a third to half of my business territory, which means these communities are my customers and my neighbours. The four utility-scale solar farms proposed there will not directly threaten my revenue. My reputational exposure is different and more important. Most Albertans do not know that there are effectively two solar industries operating in this province with almost nothing in common. The residential and commercial industry installs systems on rooftops and farmsteads and keeps the economic benefit local. The homeowner owns the generation. The savings stay in the community. The utility-scale industry builds industrial infrastructure on agricultural land, sends the financial returns to institutional investors, generates carbon credits that industrial emitters buy to justify continuing to pollute, and presents all of it as environmental progress. The public does not see this distinction. When utility-scale developers overpromise environmental benefits that the carbon credit market quietly neutralizes, and when rural communities eventually realize the deal was not what the consultation brochure described, the skepticism lands on the entire industry. I watched legitimate solar businesses lose customers because of the practices of bad actors in the broader market. Utility-scale solar is doing something similar at a larger scale. I am writing this because Albertans who live near a proposed solar farm deserve to understand which industry is actually coming to their county, and what the audited financial statements say about what they will receive in return.

A brief technical point matters for everything that follows. Alberta’s electricity grid operates on two levels. The transmission system carries power at high voltage across long distances, connecting large generators to regional substations. Utility-scale solar farms in the 125 to 465 megawatt range connect here. Their problems are primarily economic: who captures the value, and on what terms. The distribution system carries power at lower voltage from those substations to homes, farms, and businesses. Mid-sized commercial solar projects in the five to twenty-four megawatt range connect here, on the same feeders as your house. When those feeders fill, no new generators can connect. Both levels are filling with commercial solar generation. The problems are different at each level but the cause is the same: solar is being built for investors, not for the people who live on the land it occupies.

Vulcan County has Canada’s largest solar installation and its financial records are public. The Travers Solar Project is a 465 megawatt facility covering 3,300 acres of southern Alberta farmland. It cost $700 million to build. Greengate Power, a Calgary company, developed it from 2017 onward. That is a genuine Alberta success story. Construction was done by PCL, a Canadian contractor. Then the money arrives. Copenhagen Infrastructure Partners, a Danish fund managing more than 30 billion euros on behalf of international institutional investors, provided the entire $700 million in capital. [1] Less than two months after the project reached commercial operations, CIP sold its 100 percent ownership interest to Axium Infrastructure, a Montreal fund manager. CIP’s own materials describe this timeline with evident satisfaction: build the project, secure a fifteen-year power purchase agreement with Amazon covering 86 percent of output, raise $500 million in senior debt, sell, collect the development profit, move on. [2] The development profit went to Copenhagen. The ongoing cash flows go to Axium’s institutional investors. Amazon gets the carbon credits and the ESG accounting entry. Alberta provided the land, the sunshine, the regulatory access, and the grid infrastructure.

“During 2023, Vulcan County issued supplementary property tax levies as a result of one of the largest solar projects in Canada being completed and commissioned during the year. The total supplementary property tax levies were $4.033 million.” -- Vulcan County Audited Financial Statements, December 31, 2023 [3]

Four million dollars on a $700 million investment. That is a tax yield of less than six tenths of one percent of capital value, because solar farms are assessed as linear designated industrial property at provincially regulated rates rather than at market value. The county has no say in that assessment rate. It is set by the same provincial framework governing oil and gas infrastructure. The permanent employment figure is consistent across every public source: the Travers Solar Project supports up to ten permanent positions. Local officials confirmed that all renewable energy projects in Vulcan County together support around twenty long-term jobs. [4] Ten permanent jobs, four million dollars in suppressed tax revenue, and thirty-five years of financial returns flowing to institutional investors in Montreal and Copenhagen. That is the complete ledger for Canada’s largest solar installation.

There is one part of this ledger that most Albertans do not know and that the developers presenting to Sturgeon County council did not volunteer. Solar farms do not pay education tax. Not a reduced rate. Not a token amount. Nothing. The province explicitly exempts electrical power generating properties from the levy that funds Alberta schools, by ministerial order. [5] Oil and gas infrastructure fares only marginally better, paying a token Designated Industrial Property requisition rather than the school levy that applies to everyone else. The Vulcan County 2023 financial statements make this visible in a single line: school requisitions from all residential, farmland, and commercial property totalled $3.14 million. The provincial DIP requisition from all industrial property combined was $68,938. [6] Every homeowner in Vulcan County pays education tax. Every farmer. Every small business. Every person with solar panels on their own roof pays education tax. The $700 million facility on 3,300 acres pays nothing toward the schools in the county where it operates.

This is happening while Alberta’s education system runs nearly a billion dollars below the national per-student funding average. The Alberta Teachers’ Association described public schools in 2025 as in crisis, with class sizes at record levels and teachers leaving the profession. [7] The provincial government says it cannot afford to fix this while exempting a growing fleet of industrial installations from the levy that funds classrooms. The same government that tells teachers there is no money for smaller class sizes has exempted an entire category of industrial property from contributing to schools, and that category happens to include every utility-scale renewable energy project in Alberta, most of them owned by foreign or out-of-province institutional capital. This is not a federal policy. The education exemption was created by Alberta ministerial order. Ottawa did not impose it. Alberta chose it.

The feeder capacity problem operates at the distribution level and it is closing off options for homeowners and farmers right now. The wires that carry power from substations to homes and farms were built to move electricity one direction. Every commercial solar generator connected to a feeder pushes power back toward the substation. At some point the feeder is full. FortisAlberta or ATCO Electric declares a no-export zone and no new generators can connect without a costly infrastructure upgrade. The cost of that upgrade is not paid by the commercial developer whose project filled the feeder. It is presented as the option for whoever comes next. In at least one documented case in southern Alberta, an agricultural customer spent two years planning a large solar installation, ordered significant equipment with the utility’s implicit involvement, and was then told the feeder was full and the upgrade required would cost more than four million dollars. The developer whose project consumed the capacity paid nothing toward restoring it. Maps circulating among Alberta solar installers show no-export zones spreading across FortisAlberta and ATCO territory. These are not distant future problems. They are closing off options for homeowners and farmers today.

The principle that governs transmission interconnection is called cost causation: the entity whose project creates the need for an upgrade pays for it. That principle does not apply at the distribution level. Commercial generators fill feeders for free and leave the cost for whoever arrives next. This is not anti-solar. It is applying the same rule consistently across both levels of the grid.

Part One of this series explained that building more utility-scale solar under Alberta’s current carbon credit framework drives the market price of credits lower, makes industrial compliance cheaper, and reduces the financial incentive to actually reduce emissions. The net effect of more solar generation entering the TIER credit market is more affordable pollution, not less. That mechanism applies directly to every project described in this article. The solar energy is real and the physical displacement of gas generation is real. The credit market captures that benefit and sells it to industrial emitters as permission to continue polluting. Albertans host the infrastructure, provide the land, and watch both the financial return and the environmental credit leave.

There is one more benefit that is not being realized, and it will be familiar to anyone who has opened an electricity bill lately. Solar has the lowest levelized cost of energy of any generation currently being built in Alberta, roughly $30 to $50 per megawatt-hour for large utility-scale projects. In a competitive electricity market, adding large amounts of the cheapest available generation should suppress wholesale spot prices over time. Cheaper supply at the margin should push out more expensive supply and lower the clearing price for everyone. Albertans should be seeing lower electricity bills as solar capacity grows. They are not. During the period when solar has expanded most rapidly in Alberta, retail electricity prices have increased, not declined. Two mechanisms explain why the price benefit disappears before it reaches a ratepayer. First, the majority of Travers Solar output is locked into a fifteen-year power purchase agreement with Amazon at a contracted rate. That power is effectively removed from the open spot market. It does not participate in price discovery the way generation sold into the pool does. Second, the connection between wholesale spot price movements and what a ratepayer pays on their bill is indirect and frequently absorbed by retail margin rather than passed through. The wholesale benefit of cheap solar generation is captured at the contract stage by the institutional investor and the corporate PPA buyer. It does not reach the family paying their electricity bill. The environmental benefit of the generation goes to the carbon credit market. The financial return goes to institutional investors. The price relief goes nowhere. Alberta hosts the infrastructure, absorbs the land use, forgoes the tax revenue, and pays the same electricity bill. [12] He built the Heritage Savings Trust Fund on that principle, modeled on what Norway was doing with petroleum revenue. Norway has since accumulated a sovereign wealth fund worth approximately 1.7 trillion US dollars, roughly $300,000 for every Norwegian citizen. [8] Alberta stopped contributing to its Heritage Fund in 1987 and has never resumed. The fund holds about $22 billion today. The solar version of this mistake is structurally identical. No royalty on solar generation. Assessment at regulated rates that suppress tax yield. Education tax exemption by ministerial order. Power purchase agreements that send the environmental value to Amazon and the financial returns to European and Montreal fund managers. Ten permanent jobs on a $700 million asset covering 3,300 acres. Every one of these choices was made by the Alberta government, not imposed by Ottawa.

The four solar farms proposed for Sturgeon County are a joint venture between CanWest Solar Development Corp., a St. Albert family company with no prior energy construction history acting as local developer and land aggregator, and Starlight Energy, the development arm of NextEnergy Group, a fund manager headquartered in London with more than four billion US dollars under management. [9] The local developers provide community consultation and regulatory navigation. The institutional capital provides the financing and captures the returns. Sturgeon County communities should know before those AUC applications are filed what the Vulcan County financial statements show about what their county will actually receive in exchange for thirty-five years of industrial land use.

The rest of this article is about what should change. Complaining without offering something better is not the point.

The education tax exemption should be eliminated for electrical power generating properties. Solar farms should pay the same education levy that every other Alberta property owner pays. There is no principled justification for exempting a $700 million industrial installation from contributing to the schools in the county where it operates while the farmers leasing their land to the developer pay the levy on their own property. A permanent blanket exemption for a commercially mature industry is not an incentive. It is a subsidy paid by every other Albertan, including the rural communities that host the infrastructure.

The province should require an equity stake in any utility-scale solar or wind project connecting to Alberta’s transmission system. This is not a novel idea. Norway’s state energy company Statkraft is wholly government-owned and is Europe’s largest generator of renewable energy. [10] Denmark went further at the community level: its 2008 Renewable Energy Act requires developers to offer local citizens a minimum 20 percent equity stake in new wind projects, by law. [11] The participation model worked. Denmark built more than 80 percent of its electricity from renewables while maintaining public support because the communities hosting the projects shared in the returns. Alberta does not need to choose between attracting investment and capturing resource value. It needs to require that the terms of access include a provincial equity position, the returns from which flow into the Heritage Fund. Lougheed’s institution deserves a new resource. Sunshine is available.

Foreign ownership of Alberta energy infrastructure should carry a higher cost than domestic ownership. This does not mean prohibiting foreign investment. Alberta needed Copenhagen Infrastructure Partners’ capital to build Travers, and that capital performed a genuine function. It means recognizing that a $700 million asset generating thirty-five years of returns for Danish and Montreal institutional investors represents a structural transfer of Alberta resource value that should come at a price. Higher assessment rates for foreign-owned generating facilities, or a foreign ownership premium on the provincial resource access charge proposed above, would create a financial incentive for domestic and provincial ownership models without closing the door to international capital when it is genuinely needed.

At the distribution level, the first-come-first-served approach to feeder capacity must be replaced with a framework that prioritizes individual and agricultural generators. The wires connecting Alberta homes and farms to the grid are shared infrastructure built over decades by ratepayers including those same homeowners and farmers. A commercial solar developer filling a feeder and foreclosing residential access to that shared resource should be required to pay the cost of restoring it. The cost causation principle that governs transmission interconnection should apply at the distribution level. Beyond that, the AUC should establish a capacity reservation system that protects a minimum allocation of feeder hosting capacity for residential and small commercial generators in every no-export zone declaration. Commercial projects that have filled a feeder beyond that threshold should face a retroactive cost recovery mechanism that funds the upgrade required to restore residential access.

The core principle underlying all of these proposals is simple. Alberta’s sunshine is a provincial resource. It belongs to Albertans the way the oil in the ground belongs to Albertans, at least in principle. The province has consistently failed to enforce that principle for oil and gas, settling for royalty rates and assessment frameworks that leave the bulk of resource value with outside capital. Solar development is arriving under terms that are even less favourable than the oil patch at its worst. There is still time to set different terms. The Denmark model, the Norway model, and the Lougheed Heritage Fund model all demonstrate that jurisdictions can attract the investment they need while retaining a meaningful share of the value their resources generate. Alberta has the precedents. It has the institutions. The question is whether the communities hosting these projects will demand better terms before the AUC applications are filed, or accept the consultation brochure at face value and spend the next thirty-five years reading the audited statements.

Jordan Forsythe is the owner of Boreal Energy Solutions, a solar installation company operating across Alberta. Boreal Dispatch covers Alberta’s energy economy, the politics behind it, the industry inside it, and the real costs to the people it serves. Written by a working installer with roots in the patch. No sacred cows. No party lines. Just facts.

Sources

[1] Copenhagen Infrastructure Partners, Fund Overview. CIP manages approximately EUR 30 billion across eleven funds with more than 180 international institutional investors. cip.com

[2] Copenhagen Infrastructure Partners, ‘CIP divests ownership of Travers Solar,’ GlobeNewswire, January 24, 2023. CIP sold 100 percent ownership to Axium Infrastructure within two months of commercial operations commencing November 2022.

[3] Vulcan County, Audited Financial Statements, Year Ended December 31, 2023. Note 4, Tax and Grants in Lieu Receivables. Supplementary tax levies $4.033 million. Audited by KPMG LLP, Lethbridge.

[4] Canadian Energy Centre, ‘Canada’s largest solar facility operating in the heart of oil country,’ June 2023. All renewable energy projects in Vulcan County support around 20 long-term jobs. Power Technology / Construction Connect: up to 10 permanent positions at Travers.

[5] Alberta Ministerial Order MAG:016/21, Education Tax Exemption for Electrical Power Generating Properties, 2022 to 2026. Electrical power generating properties are explicitly exempt from the provincial education requisition.

[6] Vulcan County, Audited Financial Statements, Year Ended December 31, 2023. Schedule 3, Schedule of Property and Other Taxes. School requisitions: $3,138,040. Provincial DIP assessment requisition: $68,938.

[7] Alberta Teachers’ Association, ‘Budget 2025 Fails Public Education,’ February 27, 2025. ATA states $910 million shortfall against what would be needed to bring Alberta to the national per-student average.

[8] Norges Bank Investment Management, Government Pension Fund Global Annual Report 2023. Fund value approximately USD 1.7 trillion. Norway population approximately 5.5 million.

[9] Chambers and Partners, ‘Power Generation, Transmission and Distribution 2025: Norway.’ Statkraft SF is wholly owned by the Norwegian state and is Europe’s largest generator of renewable energy.

[10] World Resources Institute, ‘A Sustained Portfolio of Policies Have Transformed Denmark’s Power Sector,’ March 2024. Denmark’s 2008 Renewable Energy Act requires local citizens to be offered at least a 20 percent share in new wind projects.

[11] St. Albert Gazette, Sturgeon County council meeting coverage, March 2026. CanWest Solar Development Corp. and Starlight Energy (NextEnergy Group, London) presenting four projects: St. Albert Villeneuve (~250 MW), Meadowview, Legal (~125 MW), Lamoureux.

[12] Alberta Electric System Operator (AESO), 2024 Long-term Outlook. Solar LCOE approximately $30 to $50 per megawatt-hour for utility-scale projects. Amazon PPA: 400 MW contracted rate disclosed in Greengate Power and CIP construction announcement, June 2021. Retail electricity price trends: Alberta Utilities Commission rate filings and regulated rate option historical data, 2020 to 2025.

In 1983, economist Bruce Yandle published a paper about regulatory politics that has never stopped being relevant. [1] He noticed that Prohibition had two enthusiastic supporter groups with nothing else in common. Baptists supported the ban on alcohol because they believed it was morally wrong. Bootleggers supported it because it eliminated legal competition and made them rich. Both groups lobbied for the same policy. Both got what they wanted. Neither was honest about why. Yandle called this dynamic Bootleggers and Baptists, and it describes Canadian carbon pricing more precisely than anything the politicians involved have ever said about it.

Before going any further, let me be clear about where I stand. I do not support the industrial carbon tax. I do not think the Liberal government has been honest with Canadians about what the system actually does. I do not think the Conservative Party has been honest either. I find both positions equally cynical, and I am equally repelled by both. What follows is not a defence of carbon pricing or the government that maintains it. It is an argument that the people managing this debate on both sides, the politicians, the lobby groups, and the institutional investors behind all of them, are performing for their respective audiences while the mechanism they are arguing about quietly fails to do what either side claims it does. If you are a conservative who is angry about carbon pricing, you should be. If you are a liberal who believes it is protecting the planet, you should read this carefully.

Start with the two bases, because they are both right about something. The conservative base is right that carbon costs flow to consumers, that Canadian businesses face compliance costs their American competitors do not, and that people at the lower end of the income scale bear a disproportionate share of the burden. These are not manufactured grievances. They are economically sound observations held by reasonable people who have watched their cost of living rise. The liberal base is right that climate change is real, that Canada has a role to play in addressing it, and that pricing carbon pollution is a legitimate policy instrument that has worked in other jurisdictions. These are not naive beliefs. They are held by people who genuinely want to leave a functioning planet to their children. Both bases want the same things: affordable lives, a fair deal, and a future worth having. The leaders of both parties have taken those legitimate concerns and built a political theatre around them that serves institutional capital while delivering nothing to the people in either audience.

Canada accounts for approximately 1.42 percent of global greenhouse gas emissions. [2] The conservative argument that Canada is too small a global emitter to justify the economic cost of carbon pricing has genuine force and deserves an honest answer rather than dismissal. The counterweight is also real. Canada has the second highest per capita emissions of any OECD country, at approximately 17.9 tonnes per person per year, nearly three times the global average. [3] Some of that is structural and should be acknowledged honestly. Canada is one of the coldest, largest, and most sparsely populated countries in the world. Heating a home through an Alberta winter costs more carbon than heating one in Denmark. Driving between communities separated by hundreds of kilometres of highway costs more carbon than taking a train between European cities that actually have rail. Canada has almost no intercity rail outside the Windsor-Quebec corridor and virtually no public transit outside a handful of urban cores. A farmer in central Alberta or a tradesperson in the Peace Country is not making a lifestyle choice when they burn diesel. They are operating in the conditions of the country they live in. These are facts that belong in the same conversation as the per capita figure, and leaving them out is the kind of dismissal that tells the conservative base the debate is not being held in good faith. The fuller picture is that structural factors explain some of the per capita gap but not all of it. Canada also produces six percent of the world’s oil. The emissions from that exported oil are counted against the countries that burn it, which means Canada’s actual contribution to global emissions is significantly larger than the headline number suggests. Canada is a small total emitter, a large per capita emitter with real structural reasons for part of that gap, and a massive fossil fuel exporter whose full carbon footprint is distributed across the globe.

Canada’s industrial carbon pricing framework applies to large industrial facilities emitting more than 100,000 tonnes of CO2 equivalent per year: oil sands operations, refineries, steel mills, cement plants, fertilizer producers. The system works on an intensity basis. Each facility gets a benchmark based on emissions per unit of production and pays only on emissions that exceed that benchmark. Facilities that perform better than the benchmark earn credits they can sell. Facilities that perform worse have three options: reduce their own emissions through operational change, pay into the government fund at the headline rate, or buy offset credits on the secondary market. That third option is where the system collapses.

The headline TIER rate in Alberta is $95 per tonne, frozen there by the provincial government after it was scheduled to rise to $170 by 2030. That is the number in every political speech and every news headline. It is the ceiling, not the actual cost of compliance. The secondary market for Alberta TIER credits currently trades at approximately $18 per tonne, less than one fifth of the headline rate, because the market holds a surplus of approximately 47 million credits. [4] Suncor, Canada’s largest oil sands emitter, reported an average carbon compliance cost of approximately $2.10 per tonne in 2020. [5] The Canadian Climate Institute confirmed that industrial carbon pricing imposes an effective cost of $10 or less per tonne of total emissions against a headline price of $95. [6] Genuine operational decarbonization for an oil sands facility can cost hundreds of dollars per tonne. The rational economic choice is not remotely close. Industrial emitters pay $2 to $18 per tonne in actual compliance costs and continue operating exactly as before.

The mechanism that produces cheap credits is the carbon offset. Solar and wind farms generate electricity. Because they displace gas generation, real CO2 stays out of the atmosphere. That is a genuine physical benefit. Simultaneously, those farms generate carbon offset credits, currently quantified at approximately 0.53 tonnes per megawatt-hour of generation. [7] Those credits are registered, verified, and sold into the TIER market. An industrial emitter buys them. The emitter’s compliance obligation is satisfied. The emitter’s physical emissions are unchanged. One reduction, one continuation. The net atmospheric result is zero.

The economists who designed these systems will tell you this is not supposed to happen, because of something called additionality. For a credit to represent a genuine net reduction, the project generating it must be additional: the reduction would not have happened without the credit revenue. If a solar farm gets built because a multinational corporation signed a fifteen-year power purchase agreement before construction started, the credit did not cause the decarbonization. The solar farm was getting built regardless. The credit monetized a reduction that was already happening and sold the accounting right to a polluter. The offset is not additional. It is a fiction dressed as a reduction, and the Alberta market holds millions of them.

This is why the system fails to reduce emissions. The more important question is why the people responsible for it, on both sides of the aisle, continue to maintain it.

There are three layers to this, and they operate differently at each level. At the top are the leaders who understand the mechanism and perform anyway. In the middle are the party members who genuinely believe the message they are carrying. At the base are ordinary Canadians on both sides who have legitimate concerns and are being used as an audience for a performance that does not serve them.

Mark Carney understands carbon markets. He was Governor of the Bank of Canada and the Bank of England. He has spent his career in institutional finance at the highest level. When he announces a 16 percent increase in the industrial carbon headline rate while the secondary credit market sits at $18 per tonne, he knows that no large emitter is going to pay that headline rate. He knows the credit market renders the increase symbolic. He is announcing a press release, not a policy, and he is sophisticated enough to know the difference.

Pierre Poilievre also understands this. He campaigned to axe the tax on consumers while never once proposing to eliminate the industrial credit market that his corporate donors depend on. The industrial credit market survived every Conservative government that complained about carbon pricing. It survived Kenney. It survived Smith’s price freeze. It survived Poilievre’s campaign. That is not an accident.

The hidden hand that both performances serve is institutional capital. Firms like BlackRock, Copenhagen Infrastructure Partners, Axium Infrastructure, and dozens of other infrastructure funds have deployed billions into renewable energy assets whose investment thesis depends on the carbon credit market existing. Those solar and wind farms generate two revenue streams: power sales and offset credits. The credit revenue exists only because the industrial pricing system exists. If the credit market is eliminated, the expected returns on those assets change materially. These institutional investors manage the pension funds, sovereign wealth funds, and endowments that flow through the broader financial system to both parties. They are not partisan. They are interested in stable regulatory frameworks that protect asset values regardless of which party holds power. An industrial credit market that persists across Liberal and Conservative governments is exactly what that stability looks like.

The industrial emitters play both ends of this arrangement. They lobby for weaker carbon pricing rules and lower credit prices while benefiting from cheap compliance credits that let them avoid costly operational change. Some of them invest in the renewable assets generating the credits they purchase for compliance, effectively paying themselves. Suncor and other major producers have renewable energy portfolios that generate credits they can use or sell. They are simultaneously buyers and sellers in a market they helped design. They have no interest in a system that actually forces decarbonization at hundreds of dollars per tonne when the credit market offers compliance at $18.

Now for the part that should make every Canadian angry regardless of where they sit politically. The conservative base believes, with justification, that they are paying more because of the industrial carbon tax. Approximately 70 percent of Canadians say in polling that they believe businesses pass on most or some of the carbon cost through higher prices. [8] They are right that costs flow through. What they are wrong about is the scale, and that gap was not created accidentally. The documented effective compliance rate for Canada’s largest industrial emitters is $2 to $10 per tonne. Consumer food prices rose nearly four percent last year. The Canadian Climate Institute calculates the industrial carbon tax adds at most 0.1 percent to food prices. [9] Research confirms that 98 percent of Canadian price increases since 2018 are attributable to factors other than the carbon tax, including pandemic supply chain disruption, commodity volatility, and corporate margin expansion. [10] A 2024 study found that profit margins in 18 of Canada’s 21 largest non-financial industries remained above pre-pandemic levels in 2023. [11] Companies raised prices citing real disruptions, kept those prices elevated after the disruptions normalized, and used the carbon tax as a politically convenient explanation for what was in significant part margin expansion. The COVID grocery parallel is exact. Costs went up. Companies raised prices. When costs normalized, prices stayed elevated. The margin was embedded. Canadians blamed the government. The companies kept the difference.

“The federal government’s plan to raise the industrial carbon tax to $170 per tonne by 2030 will cost the average worker $1,160 in lost yearly income and cost 50,000 jobs.” -- Fraser Institute projection cited in Calgary Sun, April 4, 2026 [12]

Those projections assume industrial emitters pay the headline rate. They pay $18 per tonne on the secondary market. The gap between the claimed cost and the actual cost is where the political theatre lives.

On April 1, 2026, the federal government increased the industrial carbon headline rate by approximately 16 percent, from $95 to $110 per tonne. Conservative MPs posted about the Iran war, energy security, and the recklessness of raising costs on Canadian producers during a period of geopolitical instability. Liberal ministers posted about Canada’s commitment to industrial emissions reduction. It was a full performance on both sides. Meanwhile, industrial emitters across Alberta checked the TIER credit market still trading at approximately $18 per tonne and bought credits. Nobody paid $110. Nobody paid $95. The headline rate that generated a week of political content had no effect whatsoever on what any large emitter actually paid for compliance.

A reasonable question at this point is how much tax revenue the industrial carbon system actually generates for government. The answer is less than almost anyone in the debate assumes. From 2007 to 2022, total payments into the Alberta TIER fund across fifteen years amounted to approximately $4 billion Canadian, roughly $265 million per year on average. [13] Almost all of that was recycled back to industry through Emissions Reduction Alberta innovation grants rather than flowing to general government revenue. The industrial carbon tax is not a meaningful revenue mechanism. It is a compliance framework with a mandatory floor payment that the government sends back to the same industrial sector it collected it from. That floor is shrinking. From 2026 onward, industrial emitters can satisfy 90 percent of their compliance obligation through carbon credit purchases. [14] Only 10 percent must flow through the fund. The system is designed to minimize government revenue, not maximize it.

When an industrial emitter buys carbon offset credits to meet the other 90 percent of compliance, the money does not go to the Crown. It goes to the credit seller: a solar developer, an agricultural offset operator, or a carbon credit broker who aggregates credits from smaller generators and takes a margin in the middle. I know this because for a period my own company participated in it. Residential solar installations generate small amounts of offset credits. We worked with carbon brokers who packaged those credits and sold them into the TIER compliance market. We stopped. Partly because we understood what the transaction actually was: our customers’ solar systems generating a real atmospheric benefit, with that benefit being sold to industrial emitters as permission to keep polluting. But partly for a more mundane reason. The brokers hold the credits until the market price improves enough to be worth selling. The market price has not meaningfully improved. The credit surplus has kept prices suppressed. Our customers generated real offsets, handed them to a broker, and received nothing, because the broker is still waiting for a price recovery that the oversupplied market shows no sign of delivering. The credit market does not even work for the people generating the credits.

Alberta has built its political identity around this grievance for a decade. The carbon tax was the organizing principle for Danielle Smith’s career and Pierre Poilievre’s national campaign. Then Carney eliminated the consumer fuel charge, accommodated Alberta on energy development, and the grievance machine lost its engine. The separatist movement gaining visibility in Alberta right now is what happens when a political identity built on victimhood runs out of a credible villain. Some portion of the Alberta right is choosing to intensify rather than evolve, pushing toward separation not because conditions have improved for it but because the grievance infrastructure has no other outlet.

Which brings us to the conclusion that almost nobody in this debate will say out loud. Under the existing TIER framework, building more utility-scale solar farms in Alberta does not reduce industrial emissions. It increases the supply of offset credits into an already oversupplied market. More supply drives the credit price lower than the $18 per tonne it already sits at. A lower credit price makes industrial compliance cheaper. Cheaper compliance reduces the financial incentive to invest in actual emissions reduction. The net effect of more solar generation entering the current credit framework is not cleaner industry. It is more affordable pollution.

The system is not carbon neutral. It is carbon permissive, and it becomes more permissive with every solar project that adds to the credit surplus. Both bases are sitting in the congregation being told different stories about what the collection plate is for.

Part Two of this series is a concrete Alberta example of everything described above. Four utility-scale solar farms are proposed for Sturgeon County right now, backed by institutional capital headquartered in London and Milan. They will be presented to the community as environmental contributions and economic development. The audited financial statements of Vulcan County, which hosts Canada’s largest operating solar installation, tell a different story about what utility-scale solar actually delivers to the Albertans who host it. The numbers are public. The math is not complicated. And the question of who benefits when Alberta’s sunshine gets converted into carbon credits and thirty-five years of financial returns is one every Albertan near a proposed solar farm should be asking.

Jordan Forsythe is the owner of Boreal Energy Solutions, a solar installation company operating across Alberta. Boreal Dispatch covers Alberta’s energy economy, the politics behind it, the industry inside it, and the real costs to the people it serves. Written by a working installer with roots in the patch. No party lines. Just facts.

Sources

[1] Bruce Yandle, ‘Bootleggers and Baptists: The Education of a Regulatory Economist,’ Regulation, Vol. 7, No. 3, 1983.

[2] Environment and Climate Change Canada, Global Greenhouse Gas Emissions Indicator, 2022 data. Canada’s share: 1.42% of global emissions. canada.ca/en/environment-climate-change/services/environmental-indicators/global-greenhouse-gas-emissions.html

[3] Environment and Climate Change Canada, National Inventory Report 2024. Per capita emissions: 17.9 tonnes CO2 equivalent per person, 2022 data.

[4] ClearBlue Markets, ‘Navigating Canada’s Carbon Markets Ahead of the 2026 Federal Benchmark Review,’ November 2025. TIER credit bank: approximately 47 million credits. Market price: approximately $18 per tonne.

[5] Corporate Knights / The Narwhal, ‘Canada’s biggest polluters are paying the lowest price on carbon,’ 2022. Suncor average compliance cost: $2.10 per tonne in 2020, approximately one-fourteenth of the headline rate.

[6] Canadian Climate Institute, ‘Fact Sheet: Industrial Carbon Pricing in Canada,’ March 2026. Effective cost: $10 or less per tonne of total emissions against a $95 headline price.

[7] Alberta Emission Offset System, Carbon Offset Emission Factors Handbook, Version 3.0. Electricity generation displacement factor: 0.53 tonnes CO2e per MWh (projects initiated 2023 or earlier).

[8] Leger poll cited in Canadian Taxpayers Federation, ‘Scrap Carbon Taxes and Cut Gas Taxes to Ease Pump Prices,’ 2026. Approximately 70 percent of Canadians say businesses pass on most or some of the industrial carbon cost.

[9] Canadian Climate Institute / Ross Linden-Fraser, ‘Industrial carbon pricing is not the reason our groceries are more expensive,’ March 2026. Effect on food prices: at most 0.1 percent.

[10] Institute for Research on Public Policy (IRPP), ‘Does Emissions Pricing Hurt Affordability? Quantifying the Effects on Canadian Households,’ December 2024. Approximately 98 percent of price increases since 2018 attributable to factors other than the carbon tax.

[11] Canadians for Tax Fairness, corporate profit margin study, June 2024. Profit margins above pre-pandemic levels in 18 of 21 largest non-financial industries in 2023.

[12] Kris Sims, ‘Alberta should have zero carbon taxes,’ Calgary Sun, April 4, 2026. Fraser Institute projection cited: $1,160 per worker in lost income, 50,000 jobs. Fraser Institute, Ross McKitrick, ‘Carney’s industrial carbon tax comes with real cost to Canadians,’ March 2026.

[13] International Carbon Action Partnership (ICAP), Alberta TIER Regulation Factsheet, 2024. Total fund payments 2007-2022: approximately CAD $4 billion.

[14] Technology Innovation and Emissions Reduction Regulation, Alberta Regulation 133/2019, as amended. Credit use limit: 90 percent of total compliance obligation from 2026 onward.

Part Two of Two | Boreal Dispatch | Jordan Forsythe

Alberta farmers built their own power grid in the late 1940s because the utilities would not do it. They owned that infrastructure for decades through their Rural Electrification Associations. When deregulation arrived in 1996, the grid was sold through a chain of transactions that Albertans had no vote on, and the acquisition costs were added to the regulated rate base each time, meaning ratepayers funded every purchase. Today 32 REAs survive out of the original 381. Each one that sells is gone permanently. This article explains the mechanism nobody told you about, what it has cost, and what can still be done.

In Part One I wrote about how Alberta farmers built their own power grid. They organized into Rural Electrification Associations, pooled their capital, contributed their labour, and built the infrastructure themselves. By the mid-1950s they had electrified more than 90 percent of Alberta farms. They did it through collective market power, which is the only effective tool individuals have when they face a monopoly on something they cannot do without. This is Part Two. It is about what happened to what they built.

The 1995 Bet

Ralph Klein’s PC government passed the Electric Utilities Act in 1995, taking effect January 1, 1996. The pitch was that competition would lower prices and attract investment. Alberta was the only province in Canada to take this step, as every other province kept regulated utilities, and the Act deregulated generation while leaving transmission and distribution as regulated natural monopolies. The people who raised concerns were told they did not understand markets.

What actually happened is documented. Albertans have paid an estimated $24 billion more for electricity since 2001 than they would have under a regulated system. In January 2024, the Alberta Emergency Management Agency issued a grid alert during a cold snap: high risk of rotating blackouts, multiple private generators offline, wind and solar near zero. The regulated grid had never produced that kind of failure. The deregulated grid has produced several. The generation market is not the main subject here, though. The deregulation story that directly concerns the REAs happened in distribution, and almost nobody has told it plainly.

The Chain of Transactions

Before deregulation, Alberta’s major investor-owned utilities were vertically integrated. They generated power, transmitted it, and distributed it to customers. The new structure required those functions to separate. TransAlta chose to exit the wires business entirely, selling its Alberta distribution assets to Aquila, an American company out of Kansas City, for approximately $900 million in 2000. TransAlta booked the gain and moved on. Aquila then got hurt badly in the California electricity crisis of 2000 and 2001, and sold its Alberta and BC distribution assets to Fortis Inc., a utility holding company out of St. John’s, Newfoundland, in 2003 for $1.36 billion. Those assets became FortisAlberta. In the north and east of the province, ATCO Electric had been consolidating its own distribution territory through REA acquisitions since the mid-1970s and continued to do so. Two different companies, one regulatory framework, same mechanism.

The infrastructure serving most of rural Alberta today is owned by companies that were not here when it was built. The farmers who built that system had no vote in any of those transactions. Their only role was to keep paying their bills.

The Y-Factor: Paying for It Twice

What follows is the part of this story that most people have never had explained to them. When a regulated utility acquires assets, it applies to the Alberta Utilities Commission to add the acquisition cost to its regulated rate base, the figure the AUC uses to calculate the return the utility is entitled to earn. A bigger rate base means a bigger entitled return, which means higher customer rates. This mechanism is called the Y-factor, and both FortisAlberta and ATCO Electric operate under it. It is not a company policy. It is the regulatory framework.

Under Y-factor treatment, the utility recovers its acquisition costs through your bills over the following decades, plus a regulated return on those costs the entire time. The utility does not absorb the risk of overpaying for an acquisition; you do. The utility does not fund the purchase from shareholder capital; you do. The utility gets the asset and a government-guaranteed return on what it cost. You get the bill.

Two concrete examples from 2015. The Kingman REA sold to a distribution utility for $5.1 million, roughly $22,600 per connection. The VNM REA sold the same year for $16 million, roughly $25,000 per connection. Combined, the acquiring utility paid $21.1 million for 866 service connections. Under AUC-approved Y-factor recovery over 30 years at standard regulated return parameters, those 866 families will collectively repay approximately $56.3 million through their power bills. The utility paid $21.1 million and will collect $56.3 million. The asset stays on the books permanently after the recovery period ends.

This is not an accusation against any specific company. The utilities applied for regulatory treatment the AUC has approved consistently for decades and acted legally within the established framework. That is precisely the point. The framework produces this outcome every time, systematically, regardless of which utility is doing the acquiring. Now apply that logic to the entire chain of transactions. When TransAlta sold its distribution assets in 2000, the acquisition cost went into the rate base and came back from Alberta ratepayers. When those assets changed hands again at a higher price in 2003, the new acquisition cost went into the rate base and started coming back again. The same infrastructure changed hands at escalating prices, and both acquisition costs were charged to Alberta ratepayers, on top of what it originally cost to build the system. The farmers who built it paid once with their labour. Their grandchildren paid again at the first sale. They are paying a third time right now.

In a real market, an investor who overpays absorbs the loss, because that risk is what ownership means. The Y-factor strips that risk from the investor entirely and transfers it to captive customers who have no other distributor to choose. The shareholder gets the asset. The ratepayer assumes the financial exposure of the acquisition decision. This is not capitalism. It is a government-backed guarantee using monopoly position to protect investors from the consequences of their own decisions, funded through mandatory charges on people with nowhere else to go.

The Second Wave

The first wave of REA sales ran from roughly 1974 to the early 1990s for organic reasons: aging boards, succession failures, financial pressure from aging infrastructure, member disengagement. The Eckville REA, where my great-grandfather Charlie was a founding director, sold in that first wave. The founding directors got old, a son replaced a father on the board, the son pushed to sell, the meeting voted yes. That is a governance failure, not predation.

The second wave, accelerating after 2012, is different in kind. The conditions outside the room are now working against REAs in ways the first wave never faced. Post-deregulation compliance requirements were designed for investor-owned utilities with professional management, legal departments, and engineering staff, and those same requirements apply equally to volunteer boards managing co-operatives with a few hundred members. A utility compliance team and an REA volunteer board face identical regulatory obligations; one handles them at marginal cost, and the other burns board-meeting hours on paperwork that did not exist before 1996.

The Rural Utilities Act prevents REAs from serving commercial or industrial customers in their service areas, which blocks the revenue diversification that could make them financially viable long-term. A co-operative that can grow its customer base does not need to sell. At the transmission level, the cost causation principle is clear: whoever creates the need for infrastructure upgrades pays for them. At distribution level, commercial developers can consume feeder hosting capacity and push the upgrade costs onto REA members and other ratepayers. The rules that apply to REAs are not the rules that apply to the capital acquiring them.

Fifteen REAs have sold to investor-owned utilities since 2012, and the surviving count has dropped from 154 to 32. The pattern is the same every time. A board under pressure gets an offer. The offer looks fair by the metrics in the room. The cash feels like a win. Nobody in that room has seen the thirty-year Y-factor recovery schedule they just approved, and nobody explains that their rate base just increased by the acquisition cost, plus a guaranteed return on that cost, for life.

The Wheat Board Lesson

The western Canadian grain co-operative system did not end because farmers voted it away. The provincial pools merged into Viterra through a series of corporate transactions over the late 1990s and 2000s. The Canadian Wheat Board, the last mechanism giving prairie farmers collective bargaining power against global grain multinationals, was dismantled in 2012 by a federal government that ignored a farmer plebiscite in which 62 percent of wheat growers voted to keep the single desk. The Board’s assets were then handed to a joint venture of a Missouri corporation and a Saudi sovereign wealth fund for $250 million, without the farmer vote that existing law required.

The political framing that made this palatable was built on a real grievance. Ontario farmers could sell their wheat to whoever they chose while prairie farmers could not, and the question of why eastern farmers should have freedom that western farmers were denied landed hard in a region with deep and justified feelings about being governed in the interests of central Canada. Many western farmers supported dismantling the single desk because it felt like taking back control. What they got was the freedom to negotiate individually against Bunge, Richardson, and Cargill, three companies that following Bunge’s completed merger with Viterra in July 2025 now control the overwhelming majority of Canadian grain handling capacity. The people who sold western farmers on Wheat Board freedom delivered their collective assets to a company headquartered in Missouri and a fund owned by the Saudi government. If keeping western grain wealth in western hands was the goal, that was not the outcome.

University of Saskatchewan economists calculate that the Bunge-Viterra merger alone reduces prairie grain producer income by $770 million per year in lost negotiating leverage, the annual cost of going to market alone against a company that controls roughly a third of Canadian primary elevator capacity and a significant stake in the largest grain terminal at the Port of Vancouver. It is not an ideological number. It is arithmetic: one side of the transaction has collective scale and the other does not. The REA story is on the same trajectory. Once co-operative infrastructure is sold to an investor-owned utility, it does not come back. The capital and regulatory requirements for a community to repurchase its own distribution system are prohibitive. No REA from the first wave has reconstituted itself. None from the second wave will. Each sale is permanent, and the window closes.

Somewhere in Alberta right now there is an REA board meeting where someone is making the same argument that was made at Winterburn in 1974 and at every sale since. The argument sounds reasonable. The offer is fair by the metrics on the table. Nobody in the room has seen the rate schedule. Once they vote yes, it is over. Not difficult to reverse. Over.

Not a Free Market Argument

I want to be direct about something, because the word that gets thrown at people who raise these issues is socialist, and I have watched it end conversations that should not end. The REAs were not a socialist program. They were a market solution to a market failure. When one party holds a monopoly and the other has no alternative, you do not have a market; you have extraction. The co-operative model restores the conditions for a real market by giving dispersed individuals the collective purchasing power they need to negotiate on something approaching equal terms. John Skocdopole understood this in 1905 organizing against the Line Elevators. Charlie understood it in 1947 co-founding the Eckville REA. These men were not socialists. They were farmers who understood that individual freedom in a monopoly market is not freedom. It is a slower form of being taken.

The Y-factor is the genuinely anti-market element of this story. In a real market, if you overpay for an acquisition, you absorb the loss, because that risk is what ownership means. The Y-factor removes that risk from the investor entirely and places it on captive customers with no other option. That is not capitalism. It is a government-backed guarantee using monopoly position to protect investors from their own decisions. The case for protecting REAs is not a case against markets. It is a case for what markets actually require: parties on both sides with real alternatives and real negotiating power. The REA is how rural Albertans keep a seat at that table. When it sells, the seat is gone.

What Needs to Change

The changes required are not complicated. They are identified, and what they lack is political will and organized pressure. The Rural Utilities Act needs to be amended to let REAs serve commercial and industrial customers. This is a free-market argument: remove an artificial restriction on a community-owned business that prevents it from competing for revenue it could otherwise earn. Any MLA who supports free markets and opposes unnecessary regulation can vote for this without contradiction.

Post-deregulation compliance requirements need to be scaled to the organizations they actually apply to. A volunteer board running a 300-member co-operative does not belong in the same regulatory architecture as a professional utility management team, and the asymmetry accumulates every year until the board gives up.

The Y-factor recovery on REA acquisitions should require, at minimum, that members voting on a sale receive a full accounting of the thirty-year ratepayer cost before the vote. Right now they receive information about what they will be paid. They do not receive information about what they will subsequently be charged. That is not informed consent; it is a structurally one-sided transaction enabled by a framework with no obligation to make the full cost visible.

What You Can Do

If you are a member of a Rural Electrification Association, go to your Annual General Meeting. The boards are elected by members at AGMs, and low turnout is how boards lose touch with membership. Low turnout is how a motion to sell passes because the fifteen people who showed up that night happened to favour it while the two hundred who did not never heard it was on the agenda.

If your board is aging and succession is unclear, put your name forward. The work is unglamorous and the pay is nothing, which is exactly why the founding generation’s commitment was remarkable. Nine meetings until past midnight, no pay, no expenses, because they knew what they were building. If the people running the board today are willing to sell what that generation built, it will be sold. If they are not, it will not. That simple. That local.

If your MLA represents a rural constituency, the Rural Utilities Act amendment is a legitimate ask with a credible argument. Take the article. Make the case. The REA is not a relic. It is the market solution to a monopoly problem, still working in 32 communities that chose to keep it.

The Wheat Board is gone. The grain elevators are gone. The co-operative grain handling infrastructure that kept margin in prairie communities for most of the twentieth century is gone, and no policy is bringing it back. The REAs are not gone yet. Thirty-two of them are still operating, still owned by the people who use them, still governed by boards accountable to farmers and acreage owners rather than to shareholders in Newfoundland or anywhere else. The window is still open. It does not stay open by itself.

My great-grandfather Charlie organized the Eckville REA in 1947 because he had watched his father John organize a grain elevator in 1905 against the same kind of concentrated capital, and he understood what happens when ordinary people have no organized market position. He built the machine that dug the holes because the old way was too slow and he could do better. He sold it to the next REA when Eckville was done because the point was never to own the machine. The point was to get the lines in the ground.

Once it is gone, it is gone. The generation that built this knew it. The question is whether this generation understands it before the vote, or after.

Sources

The history of the Eckville Rural Electrification Association is drawn from a written history published in a Lacombe County community history book, a copy of which was provided by family members.

The broader history of Rural Electrification Associations in Alberta draws on Country Power: The Electrification of Rural Alberta, published by the Alberta Federation of Rural Electrification Associations, 1993. The 1941 electrification statistics, the 1948 plebiscite vote counts, the first wave of REA sales, and the Landing REA amalgamation are sourced from that book.

The history of John Skocdopole is drawn from a biography he typed before his death in 1956, held by the family, and from the Stettler Independent.

Bighorn Dam details are drawn from a Calgary Power project brochure held by the family, dated approximately 1972.

Interviews with Ron Skocdopole and Gayle English were conducted in March 2026.

The TransAlta distribution sale to Aquila and subsequent sale to Fortis Inc. are documented in TransAlta SEC filings from 2001 and 2002 and Fortis Inc. corporate history.

REA acquisition costs and Y-factor recovery estimates are sourced from AUC decision filings and investor-owned utility financial statements, which are public record. The thirty-year recovery estimate is calculated at AUC-approved regulated return parameters applied to documented acquisition costs.

Alberta deregulation history draws on the AUC’s published History of the Electric Industry in Alberta and Alberta Views magazine reporting.

The Canadian Wheat Board dissolution is documented in the Canadian Encyclopedia, Wikipedia, and CBC News reporting from 2011 and 2012. The 2011 plebiscite results showing 62 percent of wheat growers in favour of maintaining the single desk are drawn from those sources. The sale of CWB assets to G3 Global Grain Group, a joint venture of Bunge Limited and the Saudi Agricultural and Livestock Investment Company, is documented in public filings and news reporting from April 2015.

The $770 million annual loss estimate is from a University of Saskatchewan analysis of the Bunge-Viterra merger prepared for the Alberta Canola Producers Commission. The merger completion in July 2025 is documented in public corporate filings.

The $24 billion excess cost of deregulation is from a 2024 study for the Alberta Federation of Labour by economist Edgardo Sepulveda.

The count of surviving REAs is sourced from AFREA member directories and AUC acquisition filings, current as of early 2026.

Jordan Forsythe is the owner of Boreal Energy Solutions, a solar installation company in Alberta, and the publisher of Boreal Dispatch.

Part One of Two | Boreal Dispatch | Jordan Forsythe

Rural electrification near Irma, Alberta, 1951. Glenbow Archives, NA-4160-19.

Sometime in the late 1930s, my great-grandfather Charles Skocdopole put up a wind turbine on his homestead near Botha. The grid had not arrived. The utilities had no plans to build it out that far. So he built his own power. Today, wind energy is one of the most politically charged subjects in Alberta. Back then it was just a farmer solving a problem with what the landscape gave him.

I install solar panels for a living. My father Brad surveyed the Bighorn Dam in 1972, his first job out of high school before oil and gas took him in a different direction. My uncle Rod earned his journeyman ticket as a substation power technician with Calgary Power. My grandfather Ralph English spent the better part of two decades maintaining Calgary Power’s hydro dams in the mountains west of Calgary. And my great-grandfather Charlie co-founded the Eckville Rural Electrification Association in 1947, organized the farmers who built its lines, and built the machine that dug the holes for the poles. Four generations, every one of them with hands on Alberta’s energy infrastructure, connected by a thread that runs one generation further back to a man who understood, before any of them were born, exactly what happens to ordinary people when concentrated capital holds a monopoly over something they need. This is that story. It belongs to more families than mine. Part Two will explain what it is costing us that so much of it has been sold.

The Man Who Understood Monopoly

Before Charlie, there was his father John. John Skocdopole arrived at Blackfalds on March 31, 1905, with his wife Marie, a nine-month-old son named Charles, two cows, three mules, and a gross of hens. He homesteaded near Botha in the Stettler district. Within a few years he had identified the problem that would define his public life: monopoly. The CPR set the freight rates that determined whether your harvest was worth hauling. The grain companies running the line elevators set the price they paid for your wheat. Neither was a competitor. Both were toll booths. They extracted margin from farmers who had nowhere else to go. John wrote about this in the Stettler Independent without diplomatic softening. He called the income tax a cancerous growth to the farmer and producer. He had no patience for anyone, from any direction on the political spectrum, who he believed was taking advantage of rural people.

His answer to monopoly was organization, which is the only answer individuals have when they face a supplier with no competition. In 1905 he called a meeting, hired canvassers to ride the district on horseback signing up members, and built the Botha Farmers’ Elevator to compete directly with the Line Elevators. On opening day, 129 wagon loads of wheat arrived. The farmers had created their own buyer. The margin stayed in the community. This is not a socialist idea. It is the most basic market idea there is: when one party holds a monopoly, the other party’s only effective move is to organize.

John died in 1956 at 83, having typed his own biography on a portable typewriter in his last years. His son Charles spent his life watching his father make the same argument in successive forms, and then made it himself. The argument was about grain in 1905. By the late 1940s, when Charlie was farming near Hespero west of Eckville, it was about electricity.

Charlie

Charles Skocdopole had a grade six education. At eighteen he attended the Sweeney automobile school in Kansas for six months, learning motor vehicles at the exact moment cars were first arriving in rural Alberta. He came home, worked in a garage in Botha, went moose hunting, and found a Dear instead. He asked Mildred to marry him three days after they met. He was twenty years old. He built a shop on his property and became the person you called when something needed fixing, not just in his family but across the community.

My grandmother Gayle English, Charlie’s daughter, describes him plainly. He would stop his own work to go help somebody who needed it. His sons Ron and Glen would push back sometimes. We are losing work right now, they would say. His answer never changed. We will be all right. Don’t worry about it. We have to go do this now. If you had money you paid him. If you were a poor farmer in a hard stretch, he found a way to let it go.

He sat on the Local Improvement District board for twenty-four or twenty-five years, elected every term, opposed only once, and that person lost badly. When the LID became a county and the position started paying six hundred dollars a year, Charlie quit. He would not be paid to serve his community. That was the line and he did not cross it.

He built one of the first grain dryers in Alberta. Wet grain was a problem that cost farmers money and had no good solution at the farm level. Charlie built a propane-powered dryer and charged by the bushel. Farmers came in by horse, sometimes well into winter, with loads of wet grain. The grain went in heavy and came out lighter because the moisture was gone. Some farmers thought they were being cheated. Charlie had to explain, more than once, that dry grain simply weighs less. The dryer ran flat out through fall and early winter.

He put up a wind turbine at Botha in the late 1930s because the grid had not arrived and waiting was not his nature. The voltage was unreliable and the technology crude. That was not the point. The point was that a problem existed and he addressed it with what he had. His father had done the same with the elevator co-op in 1905. The impulse was inherited.

Nobody would ever say Charlie was a socialist. My grandmother says this with the certainty of someone who does not need to think about it. He was a businessman who ran a construction company, a grain dryer, a welding shop, and a brush-cutting operation. He was an entrepreneur. He also believed that what you build in a community stays in the community, and that the people around you are the foundation on which anything you achieve personally is built. He never saw a contradiction between those two things. Neither do I.

Dark Farms

In 1941, only 5.4 percent of Alberta farms had electricity of any kind, and fewer than one percent had central station service from a utility. The rest ran on coal-oil lamps and gas engines and manual labour. Farm women carried water, heated irons on wood stoves, and washed by hand or with gas-powered wringers that took thirty minutes to start. The gap between farm and city life was not abstract. It was in your back every morning.

The power companies had built transmission lines across large sections of Alberta by the late 1920s, so the infrastructure to reach rural customers existed. What did not exist was a business case. Running distribution lines down sparsely populated country roads for a few customers per mile did not produce a return at rates farmers could afford. The utilities were not villains for making that calculation; they were investor-owned companies doing what investor-owned companies do. But the calculation left the countryside dark.

The provincial government argued about it for two decades. Should Alberta follow Ontario and build a public utility? Premier Manning did not want public ownership. He believed government should set direction and stay out of the actual work, and in the post-war political climate with the CCF gaining ground in Canada, his position had both ideological and electoral logic. The debate went to a vote on August 17, 1948, when Albertans voted in a plebiscite on whether to purchase the private power companies and create a public utility. The result, properly counted, was 139,991 votes for private ownership against 139,840 for public, a margin of 151 votes out of 279,831 cast. Manning had already declared it an emphatic repudiation of the socialist threat, based on an early count that was wrong by about 9,000 votes. When the real numbers came in, he declined a recount. Private power had its mandate, settled by a coin flip’s worth of votes.

Private power still could not profitably wire the countryside, and the farmers still needed electricity. The solution that came out of that problem was neither public ownership nor private utility service. It was a third option, uniquely Albertan, and it came from the farmers themselves.

The Bar and Spoon

The Rural Electrification Association model was straightforward. Farmers in a district organized a co-operative, signed up members, collected cash deposits, and negotiated with the power company to build the lines at cost with farmer capital. The power company supplied the power. The REA owned the infrastructure it had paid to build. Government loans at low interest supplemented member equity for farmers who could not cover the full cost, and many farmers in the Eckville and Hespero area in the late 1940s could not, so they paid in labour instead.

The holes for the power poles had to be six feet deep, per Calgary Power’s specifications. Three feet with a shovel is work. Six feet is a different problem. The standard method was the bar and spoon: the bar was a ten-foot piece of crowbar steel, flat on one end and pointed on the other; the spoon was a round twelve-inch disk on a long handle. You drove the point down to break the soil, worked the spoon down to lift the dirt out a few inches at a time, six feet through Alberta clay and rock and groundwater, then pulled everything out and moved to the next hole. Hundreds of holes. Hard, slow work.

Charlie looked at it and decided there had to be a better way. He had two old army trucks running in his brush-cutting operation. He mounted a framework in the back of one and fitted a Wisconsin air-cooled engine driving a mechanical auger he built himself. Drive the rig to the hole location, slide the auger out, drive it down, pull it back, move on. What had been an all-day manual task became something a small crew could run through in a fraction of the time. Roughly 800 holes were dug with the machine on the Eckville project, and another 200 by hand where the equipment could not reach. When Eckville’s lines were in the ground, the machine was sold to the next REA, then the next, traveling through the system one association after another, each one getting the benefit of something that had started in a shop near Hespero.

The utilities were digging holes by hand. A farmer near Hespero built a machine that did it mechanically, sold it to the next REA, and the next. The technology did not flow from the utility to the farmers. It flowed from the farmers to each other.

Nine Meetings Until After Midnight

The first organizational meeting of the Eckville Rural Electrification Association was held July 3, 1947, in the community hall at Eckville. The provisional board included Harry Bice of Condor, Albert Hansen of Diamond Valley, Charles Skocdopole of Hespero, Clyde Stauffer of Evarts, and Adolph Roke of Evergreen. Nine meetings followed before the first annual meeting on March 6, 1948, most of them running past midnight, the directors covering enormous distances between sessions, signing contracts, negotiating with Calgary Power, and working through the organizational and financial structure of something that had never existed in their district before. They received no pay and no expenses until the February 1951 annual meeting, when members voted them four dollars per meeting and mileage.

The project cost $110,000, with 176 members paying $645 each for a connection. Many of them did not have $645, so they paid with their hands: clearing brush for the right-of-way, digging holes, handling poles, doing the physical work of building a distribution grid because it was the only currency they had and because farming in the dark was not something they were willing to keep doing. The Eckville REA was incorporated January 21, 1948. First power came on March 10, 1949. A banquet was held June 2, 1949 to celebrate. The association eventually served 330 subscribers across more than 200 square miles.

Clyde Stauffer became president of the Eckville REA on February 28, 1949, and held that position until March 12, 1974. In 1950 he became the first president of the Alberta Union of Rural Electrification Associations and held that role for twenty years. Albert Hansen and his wife Hazel ran the secretary duties for seventeen years. Charlie Skocdopole served as a founding director, built the machine that dug the holes, and helped light up 200 square miles of central Alberta. His father John had organized 129 wagons of wheat against the Line Elevators in 1905. His son was organizing farmers against the power company’s preferred terms in 1947. Same argument. Same tactic. Different commodity.

What They Built

By the mid-1950s, Alberta had 381 Rural Electrification Associations, and nearly every farmer with power belonged to one. Within a decade of the first associations organizing, more than 90 percent of Alberta farms were electrified. The province that had been almost entirely dark in 1941 was lit up by 1955. No other province did it this way. Every other province built a public utility or let private utilities expand at their own pace. Alberta did it through farmer-owned co-operatives because the other options had failed, and because the farmers were not willing to wait.

The system they built was substantial. The REAs served tens of thousands of farms across hundreds of thousands of square kilometres. Each owned its own infrastructure, had an elected board accountable to members, and maintained reserve funds for future rebuilds. At the provincial level, AUREA won rate decisions at the Public Utilities Board in 1969 and 1970 that held power costs down for REA and non-REA farm customers alike. When the REAs were at full strength they had real market power and they used it.

Building the Generation Side

While Charlie and the other founders were organizing distribution co-operatives across rural Alberta, other members of the family were on the generation side. My grandfather Ralph English came to work for Charlie in his early twenties, starting as an employee and eventually marrying into the family when he and Gayle English started their life together. He built a reputation as someone who could do anything with his hands and who ran his crews the way Charlie ran his shop, working alongside his men rather than above them. At Ralph’s funeral, a former employee who had been out of contact for thirty years showed up to say he had patterned his entire working life on the way Ralph treated the people who worked for him.

Ralph’s construction company built a relationship with Calgary Power that eventually meant no more bidding on jobs. Calgary Power knew what they were getting. The work was seasonal, spring through fall, from the early 1970s through to about two years before Ralph died in 1987. At Lake Minnewanka in Banff National Park, Ralph built a new metal spillway to replace a wooden one that had rotted out. My grandmother Gayle English went out on that lake by boat not long ago. The spillway her husband built is still there.

My uncle Rod worked with Ralph on those jobs during summers while he was completing his electrical engineering technology training, then went on to earn his journeyman ticket as a substation power technician with Calgary Power. Ralph at the dams, Rod at the substations that stepped transmission voltage down to distribution level: two generations of the same family working at different points in the same system.

The Bighorn Dam is the largest project from that era connected to the family. Built on the North Saskatchewan River eighty miles west of Rocky Mountain House, it came online in December 1972 at 120,000 kilowatts. The original estimate was thirty million dollars; inflation pushed it to forty-five million, and Calgary Power absorbed the overrun. Skocdopole Construction was involved from before ground was broken, in the pre-construction phase when the site was being prepared and access infrastructure was being established. My father Brad was on the same project that year as a surveyor for Montreal Engineering, his first job out of high school before oil and gas took him in a different direction. The connection is real even if utilities was not where his career went. He was there, on the same project my great grandfather’s company helped build from the start.

I install solar panels. My father surveyed the Bighorn Dam. My uncle Rod earned his journeyman working Calgary Power’s substations. My grandfather Ralph maintained Calgary Power’s hydro infrastructure in the mountains for fifteen years. My great-grandfather Charlie co-founded the Eckville REA, built the hole-digging machine, and put up a wind turbine at Botha when the grid had not yet arrived. His father John organized 129 wagons of wheat against the CPR in 1905 and understood before any of them were born that ordinary people have to organize or they will be taken. Five generations, each one building something, each one making the same argument in the language of their time.

The First Cracks

In late 1974, the Winterburn REA, just west of Edmonton, sold its assets to Calgary Power, the first in the province to do so. By the early 1990s, roughly 200 had followed. My uncle Ron, one of Charlie’s sons, describes what happened in plain terms. The founding directors got old, he says. A son replaced a father on the board. The son did not really support the REA and pushed to sell. They held a general meeting and voted to sell to Calgary Power.

That is the whole story of the first wave. The founding generation built something and understood what it was. Their children inherited board seats without having built anything, looked at the compliance burden and the meeting schedule and the cost of aging infrastructure, and took the cash distribution instead. In many cases it genuinely felt like being paid twice: they had already received the electricity the REA was built to deliver, and now they were getting a cheque on top of that. For poor farming families in the 1970s, that money was real. The problem was not any one decision. It was what was lost in aggregate, invisibly, from inside the room where the vote happened. An REA that sold in 1980 for a cash distribution looked like a win that night. What it looked like on the rate schedule over the following thirty years was different, and nobody explained that part to the people voting. More on that in Part Two.

What stopped the bleeding in the first wave was amalgamation. REAs that merged with neighbors instead of selling got the scale to manage compliance, rebuild infrastructure, and keep their governance functional. The Landing REA in northeastern Alberta, formed from five struggling associations in the late 1970s, proved it could work. By the early 1990s, sales had nearly stopped. The surviving 154 associations had negotiated a new master agreement with the utilities in 1986. Relations were better than they had been in decades. The co-operative model had survived the first wave. Then the rules changed.

1995

In 1995, Ralph Klein’s PC government passed the Electric Utilities Act. It took effect January 1, 1996. The stated rationale: competition would lower prices and attract investment. Alberta was the only province in Canada to take this step. Every other province kept regulated utilities. The Act deregulated generation while leaving transmission and distribution as regulated natural monopolies. It was the beginning of a restructuring that would move Alberta’s distribution infrastructure through a chain of ownership changes that Albertans had no vote on, funded through a mechanism that most Albertans have never had explained to them.

The REAs that had survived the first wave were about to face a second one, and this time the conditions outside the room would be working against them in ways the first wave never had to deal with. That story is Part Two.

My uncle Ron put it simply when I asked him what people today need to understand about what that generation built. If nobody starts something, nothing happens. That generation built the foundation. They worked together and made progress possible.

The wind turbine at Botha. The 129 wagons of wheat. Nine meetings until past midnight. The machine built near Hespero that traveled from REA to REA until the holes were all dug. The lights coming on across 200 square miles of central Alberta on March 10, 1949. None of it happened because someone waited for the utilities to do it. It happened because ordinary people looked at a problem that affected everyone around them, decided it was theirs to solve, and built something together that none of them could have built alone. Once it is built, it can be sold, and that is the part they did not fully account for. Part Two is about the selling.

Sources

The history of the Eckville Rural Electrification Association is drawn from a written history published in a Lacombe County community history book, a copy of which was provided by family members. Dates, membership figures, costs, and the sequence of board meetings are taken directly from that document.

The broader history of Rural Electrification Associations in Alberta draws on Country Power: The Electrification of Rural Alberta, a commissioned history published by the Alberta Federation of Rural Electrification Associations, 1993. The 1941 provincial electrification statistics, the 1948 plebiscite vote counts, the account of the first wave of REA sales, and the Landing REA amalgamation are sourced from that book.

The history of John Skocdopole is drawn from a biography he typed himself before his death in 1956, a copy of which is held by the family, and from reporting in the Stettler Independent.

Bighorn Dam construction details are drawn from a Calgary Power project brochure held by the family, dated approximately 1972.

Interviews with Ron Skocdopole and Gayle English were conducted in March 2026. Quotations attributed to Ron are taken directly from recorded interview. Charlie’s character, the grain dryer, the wind turbine, and Ralph’s work history are drawn from Gayle’s account.

Statistics relating to REA sale transactions and the Y-factor recovery mechanism referenced in Part Two are sourced from AUC decision filings and investor-owned utility financial statements, which are public record.

Jordan Forsythe is the owner of Boreal Energy Solutions, a solar installation company in Alberta, and the publisher of Boreal Dispatch.

The idea is straightforward: if an article raises a question, sparks a disagreement, or connects to something you’re seeing in your own work, this is the place to say so. Alberta’s energy economy is complicated enough that no single article covers it completely, and the most useful perspective I’ve gotten over the years has come from people working inside the industry, not observing it from the outside. A lot of you are those people.

I’ll be in the chat. If a conversation warrants a follow-up piece, I’ll say so.

You can find it under the Chat tab on the Boreal Dispatch page, or through the Substack app.

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1. Get the Substack app by clicking this link or the button below. New chat threads won’t be sent sent via email, so turn on push notifications so you don’t miss conversation as it happens. You can also access chat on the web.

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2. Open the app and tap the Chat icon. It looks like two bubbles in the bottom bar, and you’ll see a row for my chat inside.

3. That’s it! Jump into my thread to say hi, and if you have any issues, check out Substack’s FAQ.

Most solar guides stop at system size and payback period. This one starts where those leave off.

You’ve installed solar. You’re on Solar Club’s net billing program. Your system is generating power. What you do with that power, hour by hour, will determine whether your investment performs the way you expected.

The math that drives everything in this guide comes down to one fact about how net billing works in Alberta.

Why timing matters

When you export a kilowatt-hour on the Solar Club HI Rate, you receive $0.35. That’s the retail energy charge passed back to you as a credit. When you import a kilowatt-hour at any time of day or night, you pay that same $0.35 energy charge plus the full transmission and distribution cost on top. After GST, that all-in import rate sits around $0.449 per kilowatt-hour.

Every kilowatt-hour you export earns you $0.35.

Every kilowatt-hour you import costs you $0.449.

The gap is $0.099 per kWh. That’s the T&D spread. It never goes away.

That spread exists because transmission and distribution charges only apply to power you pull from the grid. They don’t apply to power you generate and consume yourself, and they don’t flow back as export credits. Every time your system produces power you consume directly, you save the full import cost. Every time it produces power you export instead, you get partial credit.

This isn’t a marginal difference. Run your clothes dryer at midnight in July and you’re paying $0.449 per kilowatt-hour for power your solar system was exporting at $0.35 four hours earlier. That’s a five-kilowatt-hour load costing $2.25 in import charges instead of zero. The T&D spread on a single dryer load is about $0.50. Do that three times a week through an Alberta summer and the number becomes significant.

The credit carry-forward strategy

The HI Rate runs from approximately April through September. It’s the period when your system produces the most and the rate you receive for exports is highest. The strategy that maximizes your solar ROI isn’t just about individual loads in isolation. It’s about banking as much credit as possible during those high-production months so those credits carry you further when production drops in October.

Every load you successfully shift to solar production hours in summer reduces your import consumption and increases your credit balance. That balance doesn’t just help in June. It offsets your January bill when your system is producing a fraction of its summer output and you’re importing at the LO Rate to heat your house.

Think of your summer solar production as a financial asset. Discipline during peak production months is what makes the economics work during shoulder and winter months.

South-facing vs east-west: two different scheduling problems

This guide includes production data for two system configurations: a 9.50 kW DC south-facing array and a 9.48 kW DC east-west split array. The two systems are effectively identical in capacity — a difference of 20 watts — so every performance gap between them is orientation, not panel count.

The south-facing system produces 11,504 kWh per year against 9,113 kWh for the east-west split. That 2,391 kWh annual gap is entirely attributable to how the panels face the sun.

Expressed as specific yield: the south-facing system delivers 1,211 kWh per kilowatt of installed capacity versus 961 for the east-west split — a 26% yield advantage per kilowatt installed.

South-facing arrays deliver that energy in a sharp peak centred around solar noon. East-west split arrays produce a flatter curve with lower peak output but a longer daily production window on both ends. That difference matters when you’re scheduling high-draw loads.

If you have a south-facing system, concentrate your major loads between 10am and 2pm. If you have an east-west system, your peak capacity is lower so you can’t stack as many large loads simultaneously, but you have more flexibility at the shoulders of the day.

The loads that move the needle

Not all appliances are worth scheduling. A laptop charger draws 65 watts and doesn’t matter much when you plug it in. An electric vehicle charger draws 9,600 watts and matters enormously. The loads worth focusing on are the ones that are both high-draw and genuinely shiftable.

Air conditioning and heating: the conventional wisdom is backwards

Most energy-saving guides tell you to turn off the air conditioner when you leave for work and let the house warm up during the day. That advice was written for customers on time-of-use rates where daytime electricity is expensive. For a solar homeowner on the HI Rate, mid-day power is your cheapest power. Daytime is exactly when you should be running the air conditioner hard.

The correct strategy is thermal pre-conditioning. Cool your home to a comfortable setpoint during peak solar production hours, then let it drift naturally through the evening. A well-insulated Alberta home holds temperature for four to six hours after the compressor stops. Cool to 20 degrees Celsius at 1pm and you can often reach 10pm before the system cycles on again.

The same logic applies to heating in shoulder months. Pre-heat between 10am and 2pm, let the thermal mass do the work through the evening. A smart thermostat makes this effortless — Ecobee and Nest both support solar-aware scheduling where the system runs harder during defined daytime hours and backs off automatically as production drops.

The electric vehicle: your most valuable solar asset

If you own an electric vehicle and a Level 2 home charger, you have the single most powerful load-shifting opportunity available. Shifting from overnight to mid-day charging saves approximately $0.10 per kilowatt-hour in T&D and GST on the HI Rate, plus the full energy charge difference on any kilowatt-hours you displace from nighttime import.

For a typical 40-kilometre daily commute requiring about 11 kilowatt-hours, shifting the entire charge to solar hours during the six-month HI Rate season saves roughly $65 to $80 in import costs over that period alone. Higher-mileage drivers save proportionally more.

The seasonal scheduling guide

Alberta solar production is dramatically seasonal. Your system produces four to five times more energy in June than in December. The scheduling strategy has to reflect that.

Summer (June and July)

South-facing systems regularly hit 5 to 6 kW between 10am and 2pm. East-west systems hold 4 to 4.5 kW across a broader window. Stack everything you can between 9am and 3pm. Don’t start high-draw loads after 4pm.

The system is effectively off by 6pm and every kilowatt-hour you run after that is a full import at $0.449.

Shoulder months (April, May, August, September)

Production is strong but the daily window is shorter. South systems peak around 4.9 kW, east-west systems around 4.2 kW. Concentrate discretionary loads into the 10am to 3pm window. Spring shoulder months are typically on the HI Rate. Fall shoulder months may be on the LO Rate depending on your switch timing — the scheduling logic is the same either way.

Winter (November through February)

Be honest about what winter solar can and cannot do in Alberta. A south-facing system produces a maximum of around 3 kW at noon on a clear January day. An east-west system barely clears 2 kW at peak. The winter strategy isn’t about aggressive load shifting. It’s about minimizing unnecessary imports and letting the credits you banked through summer do their job.

Winter EV charging note: A Level 2 charger at 9.6 kW exceeds total peak production for both system types. In winter, charge your EV during off-peak hours on the LO Rate rather than trying to match a load the system can’t support. Level 1 charging at 1.4 kW is a much better match for winter solar output.

What this is worth

The load shifting strategy in this guide produces savings through two mechanisms. The first is direct import avoidance — every kilowatt-hour shifted to solar production hours is one you don’t pay for at import rates. The second is credit accumulation — fewer imports during summer means your solar credits compound faster and carry further into winter.

Combined estimated annual saving from load shifting: $601 per year.

This is additional saving on top of your solar system’s base net billing ROI. EV owners account for over 60% of the total. Shifting one vehicle to daytime charging is the single highest-impact action on this list.

The credit carry-forward multiplier

The $601 figure captures direct savings but understates the full picture. When you self-consume more in summer, you also slow the rate at which you draw down your accumulated credit balance. That means more credit remains to offset winter import costs, which compounds the annual saving.

The real compounding effect shows up in January and February. A household that maximized summer self-consumption enters winter with a larger credit balance that absorbs more of the fixed monthly charges and energy costs during the months when the system produces the least. Modelled over a 20-year loan period at 4% annual utility rate escalation, the total financial benefit of disciplined load scheduling over unmanaged consumption is in the range of $15,000 to $20,000 over the life of the system. That number costs nothing to capture beyond modest behaviour changes and a smart thermostat.

The value of orientation

For anyone still in the design phase, the orientation data in this guide makes a case worth putting numbers to. The 2,391 kWh annual production gap between a south-facing and east-west split system of the same capacity works out to roughly $659 per year in additional export credits for the south-facing system. If any portion of that extra production is self-consumed rather than exported, the value is higher.

Combined with the $601 annual load-shifting saving, a household that chooses south orientation and practices disciplined load scheduling is capturing approximately $1,260 per year in combined benefit compared to an unmanaged east-west installation. Orientation is a decision made once at install time. Load scheduling is a habit that costs nothing to build. Both matter.

The rules, clearly

• Run high-draw loads between 10am and 2pm in summer and shoulder months.

• Pre-cool or pre-heat your home during solar peak hours. Let thermal mass carry you through the evening.

• Charge your EV during the day, not overnight.

• Run your dishwasher after lunch, not after dinner.

• Shift laundry to mid-morning. Stack dryer cycles back-to-back during peak production.

• Override your furnace or heat pump schedule to run harder during solar production hours and ease off after sunset.

• If you’re replacing a gas water heater, a heat pump water heater paired with solar is one of the highest-ROI upgrades available. Ask us about our heat pump partners.

• Do not start high-draw loads after 4pm in summer or after 3pm in shoulder months.

• In winter, minimize discretionary imports and let your summer credit balance do the work the system cannot.

The solar system does the generating. Your job is to be ready to consume when it does.

Discipline in summer is what makes winter affordable.

Boreal Dispatch is an editorial publication of Boreal Energy Solutions. For questions about your system, your Solar Club rate structure, or load scheduling for your specific setup, reach out at jordan@myboreal.ca.

Look south of the 49th parallel and you’ll see what happens when a genuinely good idea gets handed to a pack of financial predators.

The American residential solar industry, a sector that was supposed to free ordinary people from dependence on monopoly utilities, is in the middle of a historic collapse. SunPower, a company operating since 1985, filed for bankruptcy in August 2024 with over $2 billion in debt. Sunnova, one of the largest residential solar financiers in the country, followed in June 2025. Solar lender Mosaic went down the same month. In total, 2024 alone produced over 100 solar company bankruptcies. A number the industry had never seen in nearly two decades of tracking. Residential solar installations dropped 31%. Six consecutive quarters of year-over-year decline. Seventeen thousand layoffs in California alone.

How does an industry built on sunshine manage to implode that thoroughly?

You let the wrong people in the door. And now those people are knocking on ours.

A NOTE FROM ME: BECAUSE YOU DESERVE TO KNOW WHERE THIS IS COMING FROM

I am not writing this from a position of detached concern. I am writing this because I am angry, and I think you should be too.

Everything I have, professionally, financially, reputationally, is in this industry. I didn’t get into solar to get rich. I got into it because I believe in something specific: that ordinary Albertans deserve the ability to generate their own power, reduce their own costs, and stop being entirely dependent on large corporations for one of the most basic necessities of modern life. In a world that keeps finding new ways to make the powerful more powerful and the rest of us more dependent, solar done right is a small but genuine act of defiance. I mean that without irony.

I have also, over the years, watched this industry attract people whose relationship to that vision begins and ends with how much money they can extract from it before moving on to the next thing. I’ve seen it up close, close enough that I once subcontracted for one of the worst offenders in this province, lasted a summer, and walked away from the money because what I was watching happen to customers was not something I could be part of.

So when I say these companies are poisoning the well, I am not speaking metaphorically. They are destroying customer trust in a technology that could genuinely improve people’s lives. They are handing ammunition to everyone who wants to dismiss solar as a scam. And they are threatening the futures of every honest installer in this province who has spent years building something real.

That is personal. It is supposed to be personal. If it weren’t personal, I wouldn’t bother writing this.

I also want to be transparent about one more thing before going any further: we use some of the same financing products I’m going to describe in this article. The difference, and it is the only difference that matters, is that we don’t hide what those products actually are. We show customers the real numbers. We show them what accessing that financing does to their return on investment and their payback window. We present it honestly, as a last resort for people who want to proceed but can’t pay cash or haven’t explored better options. And our first recommendation, every time, is to explore a HELOC or mortgage refinance before touching a solar-specific loan. The tool isn’t the problem. The lie is the problem.

The tool isn’t the problem. The lie is the problem.

THE SCAM THEY PERFECTED SOUTH OF THE BORDER

Here’s the thing about solar energy that the sharks figured out early: most people can’t write a $25,000 cheque. So about 85% of American residential solar systems are financed. And where there’s financing, there are opportunities to hide a lot of nasty surprises in the fine print.

The U.S. Consumer Financial Protection Bureau eventually got alarmed enough to issue a formal warning. What they found was systematic: lenders were building hidden fees directly into the loan principal, calling them ‘dealer fees’ or ‘program fees’ or ‘platform fees,’ whatever sounded most benign that week. These fees typically increased the loan cost by 30% or more above the actual cash price of the system. In some cases they exceeded 50%. The solar marketplace EnergySage found that dealer fees on the most popular loan products averaged 47% in the latter half of 2023.

“These fees are rarely shown to the customer. They increase the total loan amount and make the interest rate look artificially low.” (U.S. Consumer Financial Protection Bureau)

Here’s how the trick works in plain language. A salesperson shows up at your door and offers financing at zero percent interest. That sounds incredible. It is. Because buried under that attractive rate is a massive upfront fee the install company paid to the lender to buy down the interest rate, and they quietly recovered that fee by inflating what they charged you for the system. You’re not getting a cheap loan. You’re getting an inflated system price and borrowing that inflated amount. The low interest rate is a magic trick, and your wallet is the one that disappears.

On a $30,000 system, a 30% dealer fee means you’re actually borrowing $39,000, with the lender pocketing $9,000 that appears nowhere in what you were shown. Pay the loan off early? Doesn’t matter. That fee was baked in from day one. It cannot be undone.

The result was predictable. Homeowners across America ended up locked into 20- and 25-year agreements for systems they overpaid for by tens of thousands of dollars, with monthly payments that never delivered the promised savings. When interest rates rose and the promises didn’t pan out, demand cratered. And when demand cratered, the companies that had built their entire model on financial engineering and high-pressure sales started falling like dominoes.

This is the cautionary tale. This is what happens when you let con artists into a legitimate industry. And it is absolutely, demonstrably, happening here.

THE 0% FINANCING CON: ALBERTA EDITION

The dealer fee trick didn’t stay in America. It made the trip north without any trouble at all.

In Alberta, we’re seeing solar companies advertise financing at 0% to 4.99% interest. Sounds reasonable. Sounds almost too good. And it is, because buried under that attractive rate is a dealer fee being quietly passed on to you through an inflated system price. The actual loan carries an interest rate of 13.99% or higher. The difference between that real rate and the advertised rate is covered by an upfront fee the installer pays to the lender, then recoups by charging you more for your system than it actually costs to build.

You see a low rate. You don’t see the markup underneath it. You might be paying $10,000 or $15,000 more for your system than you should, all so the company can advertise a number that makes your eyes light up.

As we said: we use some of these products too. The difference is we show you everything. We show you the cash price. We show you the financed price. We show you exactly what the financing costs you in real dollars over the life of the loan, and what it does to your payback period. We tell you plainly: if you can get a HELOC or refinance your mortgage at a lower rate, do that instead. Financing is a last resort for people who want solar but need a path to access it. It is not a selling feature. It is not magic. And it should never, ever be presented as something it isn’t.

Our standing instruction to every customer: if someone tells you that you won’t see a bill with solar, run. That is a lie, and anyone telling it is either ignorant or dishonest. You will almost certainly still pay some amount: admin fees from your utility, seasonal variation in production, system size limits that mean you draw some grid power in winter. An honest solar company tells you this upfront. A dishonest one promises a zero bill and then disappears after the cheque clears.

NORTHERN PWR / FLUENT SOLAR / NORTHERN NRG: A CASE STUDY IN HOW THIS WORKS

Let’s talk about Northern Pwr, also known as Fluent Solar, also known as Northern NRG. If the habit of operating under multiple names strikes you as a red flag, your instincts are working correctly.

This company has a documented pattern of targeting smaller communities and older, less financially sophisticated customers. They arrive with polished pitches and compelling charts about future electricity prices. And they sell systems at $5 to $8 per watt.

To understand why that number matters: a fair market price for a residential solar installation in Alberta is roughly $2,000 to $3,000 per kilowatt. Northern PWR has been documented charging $9,000 per kilowatt. A CBC News investigation found one Calgary customer who signed a contract for a 5.27 kilowatt, 13-panel system at just over $48,000. A comparable system through a reputable installer would cost $12,000 to $15,000.

That customer paid roughly three times the going rate. At that price, you will never (not in this lifetime, not with any reasonable assumptions about electricity prices or system performance) see the financial benefit that was promised. The math simply doesn’t work. The payback period becomes so long it’s practically fictional. This is not a mistake or a misunderstanding. This is extraction.

Service Alberta’s Consumer Investigation Unit received 27 complaints about Northern PWR in a single four-month window. The complaints included allegations of missing contract information, failure to process cancellations within required timelines, and, most damningly, misleading and deceiving consumers. In September 2024, Service Alberta issued a Director’s Order requiring Northern PWR to comply with the Consumer Protection Act under threat of fines and jail time.

A second Director’s Order followed, specifically ordering the company to cease charging illegal cancellation fees when customers tried to exercise their legal right to cancel, to stop misrepresenting consumer obligations, and to stop taking advantage of consumers who didn’t understand what they were signing.

Solar Alberta, the non-profit that promotes and advocates for responsible solar in this province, expelled Northern PWR from its membership.

We know this company personally, not from a distance, but from the inside. When they came to Alberta, they hired us as their installation subcontractor. They did the sales. We did the work. That meant we were on the ground, in people’s homes, installing systems we had no hand in selling, at prices we had nothing to do with setting. We worked on systems where the production couldn’t possibly justify the cost. We were the ones who had to look those customers in the eye. We lasted a summer. Then we walked away from the contract. There is no version of that work we could have done with a clean conscience, and no amount of money that changes that math.

A system priced at $8/watt doesn’t just fail to deliver promised savings. It is a financial anchor that will weigh down that household for the life of the loan.

Northern PWR’s own website, as of this writing, promises customers they can ‘say goodbye to unpredictable power bills’ and ‘start seeing savings right away.’ After multiple Director’s Orders and expulsion from the industry association, the pitch remains the same. Make of that what you will.

THE BROKER PROBLEM: THREE QUOTES, ONE OUTCOME

Solar brokers present themselves as consumer champions, positioning themselves as neutral intermediaries who shop the market on your behalf and bring you the three best quotes. In theory, this is a great idea. In practice, some of them are running a different game entirely.

Here’s how a bad broker operates. They approach installers and establish ‘preferred’ relationships that come with financial arrangements: kickbacks, referral fees, preferred margins. The installer who pays the most becomes the ‘winner’ of the three-quote process. The other two quotes are props, sometimes inflated on purpose to make the preferred quote look competitive. The customer believes they’re getting independent advice. They’re getting a curated result.

These brokers victimize both consumers and honest installers. Consumers because they believe they’re getting a fair market comparison and aren’t. Installers because legitimate companies that compete on actual quality and honest pricing get undercut by a process that was rigged before it started.

Not all brokers operate this way, and we want to be clear about that. We know one we trust without reservation (a company called Glean) that operates with genuine transparency and actually does what a broker should do. Honest brokers exist and they provide real value. But the bad ones are using the credibility of the good ones as cover, and that needs to be said plainly.

If you’re using a broker, ask them directly: do you have financial relationships with any of the installers you’re recommending? Do you receive referral fees or commissions from them? A trustworthy broker answers those questions without flinching.

WHY THIS MATTERS BEYOND YOUR WALLET

Here’s what keeps me up at night, and it isn’t the money.

Solar energy, done honestly, is one of the most powerful tools available to ordinary Albertans to claw back some control in an economy that has spent the last generation moving wealth steadily away from people like us and toward institutions that don’t know our names and don’t care to learn them. Every kilowatt-hour you generate yourself is a kilowatt-hour some utility doesn’t get to charge you for. Energy independence is real independence. I mean that.

When companies like Northern PWR go into rural Alberta and sell a retired farmer a $48,000 system that should cost $14,000, they don’t just hurt that farmer. They make solar itself radioactive. They hand ammunition to every critic who wants to dismiss clean energy as a racket. They give the whole industry the taint of the con, and that taint does not wash off easily.

The American collapse isn’t just a financial story. It’s a story about what happens when a technology with genuine promise gets colonized by people whose only interest is extraction. And extraction, we should note, is something Albertans have had quite enough of from quite enough directions already.

I got into this work because I believe fiercely in people’s right to provide for themselves, to not be dependent on corporations and institutions for the basics of their lives. I am not interested in replacing one form of dependence with another. What these predators are doing is exactly that: they are trapping people in financial arrangements they can’t escape, with technology they overpaid for, while collecting a cheque and moving on.

That is not what solar is supposed to be. It is not what I got into this business to do. And I am not going to stay quiet about it.

WHAT HONEST SOLAR ACTUALLY LOOKS LIKE

We’re not here just to light things on fire and walk away. Here’s what you should expect from a legitimate solar installation company in Alberta:

• A fair price per watt. In today’s Alberta market, a reasonable residential system runs $2.00 to $3.25 per watt installed depending on system complexity, equipment quality, and location. Anything significantly above that warrants hard questions.

• Honest savings projections. A good solar company runs your actual numbers: real consumption, real roof, real location. They give you a realistic payback period. If the payback period sounds suspiciously short or the savings sound unrealistically large, they probably are.

• Transparent financing. The cash price and the financed price should be disclosed separately, with all fees itemized. You should know exactly what you’re borrowing, at exactly what rate, and what accessing that financing actually costs you over time. If a company won’t give you a straight cash price, walk.

• Realistic bill expectations. You will almost certainly still see some utility charges: admin fees, seasonal shortfalls, grid connection costs. Any company promising a zero bill is either naive or lying. The goal is dramatic reduction, not the elimination of physics.

• Better financing alternatives first. Before you touch a solar-specific loan, explore a HELOC or mortgage refinance. In most cases, the rate will be better, the fee structure will be transparent, and you’ll come out ahead. An honest company tells you this. A dishonest one steers you toward the product that makes them the most money.

• References and longevity. A reputable installer has a track record in your province, can give you real references, and holds good standing with industry associations. Solar Alberta membership isn’t a guarantee of perfection, but expulsion from it is a meaningful red flag.

• No high-pressure tactics. You do not need to sign tonight. You do not need to act before the program expires. Any salesperson who tells you otherwise is using a technique specifically designed to prevent you from thinking clearly. That technique works. Don’t let it.

THE BOTTOM LINE

Solar is not a scam. Solar is good. I believe that with the same conviction I bring to everything else I do, and I’ve staked my professional life on it being true.

But solar, like any significant financial decision, can be turned into a vehicle for theft if you let the wrong people near it. And right now, some of the wrong people are very much present in this market, with polished websites, plausible pitches, and a talent for finding customers who haven’t yet learned to ask the hard questions.

The American solar industry didn’t collapse because solar is bad. It collapsed because too many companies built their businesses on financial engineering, inflated promises, and the assumption that customers wouldn’t look too closely at the math. When customers did look, when interest rates rose and payback periods became obviously fictional and bills didn’t disappear the way the salesperson swore they would, the whole house of cards came down.

I don’t want that here. Alberta doesn’t need another industry that promises independence and delivers debt. We have enough of those already.

Get multiple quotes. Ask for the cash price, separately from the financed price. Ask your broker if they’re getting paid by the installer. Check the company’s record with Service Alberta and Solar Alberta. Explore a HELOC before you sign a solar loan. And if someone shows up at your door promising you a zero bill and a life-changing financial miracle, remember what we tell every one of our customers:

“If someone tells you that you won’t see a bill, run.”

That advice is free. The kind of solar installation that actually delivers on its promise costs a fair price, comes with honest projections, and is sold by a company that will still be answering the phone in five years. Those companies exist. Find one.

SOURCES & DOCUMENTATION

U.S. Consumer Financial Protection Bureau: Issue Spotlight: Solar Financing (2024) | U.S. CFPB Consumer Advisory on Solar Loans (August 2024) | U.S. Treasury Department Consumer Solar Awareness Page | PV Magazine USA: U.S. Residential Solar Downturn (2024-2025) | Canary Media: Sunnova and Mosaic Bankruptcy Reporting (June 2025) | SolarInsure: Complete List of Solar Bankruptcies | Service Alberta Director’s Orders: Fluent Solar Ltd. & Northern Pwr Ltd. (2024 & 2025, Open Government Alberta) | CBC News: Door-to-Door Solar Sales Investigation (August 2025) | Solar Alberta: Industry Complaints and Membership Actions | Canadian Renewable Energy Association: Consumer Protection Commentary | EnergySage: Residential Solar Pricing Data

I’ve been installing solar in Alberta long enough to remember when getting interconnection approval felt like filing a change of address form. A minor administrative annoyance. Mostly paperwork. Done in weeks. You submitted your single-line diagram, waited, got your stamp, put panels on a roof, flipped a switch, watched the meter spin backwards, and felt genuinely good about what you’d built.

That version of the job still exists in my memory. It’s getting harder to find in reality.

Something Is Shifting

Over the past year or so, something has been shifting. Not in the policy documents. Not in the incentive structure. The shift is quieter than that, and more telling.

It’s in the engineering reviews that now stretch from weeks into months.

It’s in the voltage rise studies we’re being asked to produce before a single panel goes on a roof.

It’s in the export restriction zones that keep spreading across the map, one substation at a time.

It’s in emails from utilities full of phrases like “relatively novel scenario” and “new internal processes” and “a range of approaches we are actively considering.” The kind of careful, lawyerly language organizations use when they’re figuring something out on the fly and don’t want to commit to anything they’ll regret later.

I sat down with utility engineers recently to understand what’s actually driving all of this. I expected a complicated answer about grid modernization timelines and distributed generation modeling. What I got was simpler, and honestly a little harder to swallow.

The wires are too small. The transformers are undersized. The infrastructure going into these communities was built decades ago, built cheap, and nobody upgraded it. And now that solar is pushing power back upstream instead of just pulling it down, the system is struggling with physics it was never designed to handle.

They also said, more than once: “We are a poles and wires company. We are not anti-solar. We are obligated under regulation to keep the power on.”

I’ve been turning that phrase over ever since. Poles and wires. It’s an honest self-description, and it’s also, accidentally, a perfect explanation of the whole problem. A poles and wires company built the poles and wires for one job. The job changed. And a poles and wires company, by its own definition, is not really set up to lead the response to that change.

That’s not a solar problem. That’s a deferred maintenance problem wearing a solar problem’s clothes.

What the Grid Was Built For, and What It’s Being Asked to Do Now

Here’s what most homeowners don’t know, and what most people in the industry underexplain: Alberta’s distribution grid was engineered on a fundamental assumption. Power flows one direction. Big centralized generators push electrons outward through transmission lines, then distribution feeders, then to your meter. The whole system is built around that premise. Upstream generates, downstream consumes.

Rooftop solar breaks that assumption at scale.

When enough houses on a feeder are generating on a sunny afternoon, pushing power back upstream, you get reverse flow. Transformers sized for one-directional load are now seeing power come back the other way. Voltage regulation equipment installed to keep service entrance voltage stable is operating in a regime its designers didn’t account for.

The technical threshold that keeps coming up in interconnection discussions isn’t the one most installers track. We watch inverter terminal voltage, keeping that below 110%. The threshold utilities are focused on now is service entrance voltage staying below 106%. That’s a secondary-side overvoltage concern. Subtler, feeder-specific, caused by cumulative backfeed from a lot of small systems that each, individually, looked fine on paper.

When you see a utility asking for voltage rise studies on residential installs, that’s what they’re actually worried about. Not your system specifically. Your system is probably fine. It’s your system plus the fourteen others already on that feeder that’s the issue. And the reason those fourteen systems are stressing the feeder is that the feeder was undersized to begin with.

The Fix Nobody Wants to Pay For

The rational engineering response to undersized infrastructure in a region with high solar penetration is to upgrade the infrastructure. Bigger conductors. Properly sized transformers. Modern voltage regulation. This is not exotic technology. This is just doing the work that should have been done before the work became urgent.

But upgrading infrastructure costs money. And utilities structured as regulated monopolies with shareholders and rate cases and capital expenditure reviews are not in a hurry to spend money they can avoid spending.

So instead of upgrading, you get restriction. Export caps. Hosting capacity limits. Entire swaths of territory quietly designated as no-export zones. Applications rejected not because the solar system is poorly designed, but because the grid it’s connecting to was never properly built in the first place.

I know of one job where a customer was told they could proceed if they paid for the required grid upgrades themselves. The quote came back over four million dollars. For a single interconnection.

That’s not a solution. That’s a utility pointing at its own deferred maintenance and telling the customer the bill is theirs.

Why Smart Design Doesn’t Solve a Wire Problem

The liability posture makes a certain kind of institutional sense, even if it’s maddening from the outside. Utilities are terrified of being the organization that approved the connection that caused a feeder failure. The engineers I’ve spoken with are not bad people. They’re people operating inside a risk management culture that has decided the safest move, career-wise and legally, is to say no. Or add requirements. Or declare a zone off-limits until someone else figures out the upgrade path. Keep the power on. Poles and wires.

Here’s the part that actually stings: pre-designing with mitigation already baked in, storage, advanced inverter controls, voltage-reactive behavior, doesn’t move the needle on approvals right now. We’ve tried. The concern isn’t really about how smart your system is. The concern is about the wire it’s connected to. No amount of sophisticated control changes the physics of an undersized conductor. Until the conductor gets upgraded, the answer is still no.

Which means the friction isn’t solvable at the system design level. It’s solvable at the infrastructure investment level. And that’s a different conversation with different players.

This Is Not a New Story

None of this is unique to Alberta, and none of it is uniquely malicious. It’s a pattern that shows up wherever distributed solar reaches serious penetration.

California went through it. Hawaii went through it so hard they restructured their entire net metering program. Australia’s distribution networks are deep in it right now. Some feeders in South Australia have so much rooftop solar that the grid operator curtails exports on sunny days just to keep voltage stable. Germany. The UK. Every jurisdiction that got serious about distributed solar has hit this wall at roughly the same stage, and had to figure out what comes after “we put panels on everything and export the rest.”

The sequence is predictable: rapid adoption, localized constraints, tighter interconnection scrutiny, infrastructure investment pressure, smarter integration tools, new market structures.

We’re sitting between steps three and four right now. The infrastructure investment pressure is building. Whether that pressure translates into actual upgrades or just more restriction maps depends on regulatory will, rate case outcomes, and whether enough people in enough rooms start saying clearly that this is an infrastructure problem, not a solar problem.

That’s a political and regulatory fight. It’s just beginning.

What This Means If You’re Thinking About Solar

So what does this mean if you’re a homeowner thinking about solar right now?

The math still works. Solar in Alberta makes financial sense. The resource is genuinely good, retail rates are volatile enough that hedging against them has real value, and payback periods on well-designed systems are competitive with most other things you could do with that money. None of that has changed.

What has changed is that your installer needs to know more than they used to. The right question before designing your system isn’t just “how much can this roof produce?” It’s “what’s the hosting capacity situation on this feeder, and what does that mean for how we size this?” In some areas, that question changes the whole conversation. In others, you’re fine. You need someone who can tell the difference before you spend money finding out the hard way.

The calculus on batteries has also shifted. Storage used to be a nice-to-have. Backup power. Some extra self-consumption. A hedge against future rate changes. All of that is still true. But in a market drifting toward tighter export conditions, a battery becomes something more fundamental. It’s the thing that lets you use the solar energy you generate regardless of what the export rules look like five years from now. Self-consumption isn’t just financially smart anymore. It’s resilience against a policy environment that is genuinely uncertain.

I’m not going to tell you batteries always pencil out. They don’t, for everyone, at every system size, under every rate structure. What I will say is that the gap between “battery makes sense” and “battery doesn’t make sense” is narrowing as export conditions get more complicated. If you’re on the fence, factor in where this is heading, not just where it is today.

The Infrastructure Debt Is Coming Due

Here’s the thing I keep coming back to.

The solar industry in Alberta has, in a pretty short period of time, built enough distributed generation to materially stress distribution infrastructure across large parts of the province. That is an extraordinary thing. That is success, by any honest definition of the word.

And now we’re in the phase where success creates its own complications. The grid wasn’t ready. The utilities weren’t ready. The regulatory frameworks are straining. The industry has to decide whether to treat this as a reason to slow down or a reason to get smarter.

You already know which one I think it is.

The easy part of this business was always going to end. The part where you could design any system for any roof and assume the grid would cheerfully absorb it, that part is over in a lot of places and will be over in more. What comes next is more technically demanding, more politically complicated, and more important.

The infrastructure problem is real and it needs to be solved. Regulators need to hear clearly that the current approach, declining applications, drawing restriction maps, telling customers to fund four-million-dollar upgrades, is not a sustainable path. That pressure has to come from the industry, from customers, from municipalities watching economic development stall because a utility won’t upgrade a feeder. Poles and wires companies respond to rate cases and regulatory pressure. That’s the lever.

On the design side, the future belongs to systems built for where the grid is going. Self-consumption first. Intelligent export management. Storage as a core component, not an optional add-on. Not because the utilities deserve to have their infrastructure limitations accommodated, but because that’s genuinely the better system for the customer regardless.

The grid is telling us something. It’s telling us the infrastructure debt is coming due.

That bill gets paid one way or another. The question is who pays it, and when.

If you’re looking at solar in Alberta and want an honest read on what the current interconnection environment means for your specific situation, reach out. We’re not going to sell you something that doesn’t make sense. But we’re also not going to pretend the picture is simpler than it is.

My great-grandfather Charles was deeply involved in the first natural gas co-ops in Alberta. The family has been running a pipeline company since the 1950s. I grew up with this stuff the way other kids grow up with hockey, dinner table arguments about Alberta politics that went long after the dishes were done, summers doing grunt work on right-of-ways, uncles who had opinions about regulators before they’d had their coffee. I worked in oil and gas from the time I was thirteen until my mid-twenties. I don’t run that world anymore, I own a solar company now, which my family finds hilarious in a way they’re too polite to fully express, but I still hear things. Family dinners have a way of keeping you current.

The thought that became this article started in my uncle’s kitchen over coffee. He mentioned a guy he knows, someone I used to work for, back when I was building generators and compressors, who’s now out there building gas turbines for data centers. My uncle was curious. I got very curious. I started turning it over.

Here’s what I couldn’t shake: what if the AI data center boom isn’t really about AI at all?

I did some research to check my thinking, policy documents, AESO reports, news coverage, and what I found was that my hunch was basically right. What follows is my read on it. I’ll be straight about what’s my family-dinner speculation and what’s documented fact. I’m not an economist. I’m a guy who grew up inside this industry and now sells solar panels, which means I have a bias you should know about and a perspective that might be worth something anyway.

The Problem Nobody Talks About: We’re Drowning in Gas

Alberta has roughly 130 trillion cubic feet of natural gas in the ground. Recent reserve assessments nearly doubled that estimate, we went from fifteenth to ninth in the world among producing nations, basically overnight on paper.

That sounds like good news. It’s complicated.

The problem with natural gas is that it’s a bastard to move. You need pipelines, and pipelines in this country are a decade-long political ordeal that may or may not end with you having a pipeline. You need LNG terminals, and Alberta doesn’t have tidewater access, which is its own special geographic comedy. The domestic market is saturated. So you’ve got this enormous resource that you can’t easily get to the people who’d pay the most for it, and the price reflects that. Gas has been cheap, embarrassingly cheap, sometimes, because the market is constrained by geography and politics in roughly equal measure.

My family has been moving natural gas around this province for over seventy years —back when back when Peter Lougheed was still fighting Ottawa for what Alberta was owed and a pipeline right-of-way was just a handshake and a surveyor’s stake.

So what do you do with stranded gas?

You upgrade it.

Gas → Electricity → Data: The Value Chain Nobody’s Saying Out Loud

Here’s the logic, and I want to be clear that I worked this out before I went looking for confirmation:

Natural gas at the wellhead is worth a few dollars per GJ. Commodity, glutted market, going nowhere fast price-wise. But if you burn that gas in a turbine and generate electricity, you’ve moved up the value chain. Electricity is worth more, travels differently, wires instead of pipes, and can reach markets that gas itself can’t access without twenty years of regulatory hearings. You’ve upgraded your product once.

Now here’s where it gets genuinely interesting. If you take that electricity and run an AI data center with it, you’ve upgraded again. Compute is worth vastly more than electricity per unit of input energy. And unlike gas, unlike even electricity, data has no borders. There are no export terminals for a petabyte of AI computation. No pipeline hearings. No tanker restrictions. You can sell artificial intelligence services from a server farm in Olds, Alberta to a company in Singapore, and the only infrastructure you need is already built. It’s called the internet.

Gas → electricity → data. Each step multiplies the value. Each step removes a layer of the geographic and political friction that’s been strangling Alberta’s resource economy for thirty years.

I thought maybe I was being too clever. Then I looked up what Premier Smith said at a press conference in December 2025: that areas with a nearby natural gas resource would be the biggest beneficiaries of the data center strategy, because those resources could be consumed locally rather than exported.

That’s the play. In her own words.

A journalist named Paris Marx put it even more directly: the Alberta government is looking to attract data centers because it wants a resource-intensive industry to consume natural gas locally, instead of shipping it off somewhere else to create demand for fossil fuels.

Yeah. That’s exactly what I thought when my uncle told me his friend was building gas turbines for data centers.

The Scale of This Is Genuinely Hard to Wrap Your Head Around

Alberta’s all-time peak electricity demand, the most power we’ve ever pulled from the grid at one moment, is about 12,000 megawatts. That record was set in January 2024 during a cold snap.

By Q1 2025, the Alberta Electric System Operator had received applications from proposed data centers requesting 11,879 megawatts of new connection. By Q3 2025, that number was 20,700 megawatts.

Sit with that for a second. The data centers being proposed want more electricity than the entire province has ever consumed at its peak. If even a meaningful fraction proceed, Alberta’s electricity demand roughly doubles.

One single proposed facility, a $10-billion Synapse project planned for Olds, would consume as much power as the city of Edmonton. They’re building a natural gas plant on the same site to feed it. It would be the second-largest power plant in the province.

The guy my uncle mentioned? He’s not building one project. This is a whole industry spinning up, right now, in the province where my family has run pipelines since Dief was the Chief. These aren’t announcements. These are job sites.

So What Does All This Do to Your Bills?

This is the part that gets almost no attention amid all the breathless coverage of billions in investment and Alberta’s glorious digital destiny.

Alberta has a deregulated electricity market. That’s unusual, we’re the only province that works this way. There’s no public utility setting your rate. Prices are set by supply and demand in real time. When demand increases sharply and new supply takes years to build, prices go up. For everyone connected to that market. That’s not a political opinion, it’s arithmetic.

Fixed electricity rates are priced off futures contracts — what the market expects power to cost in coming months and years. Those futures prices have already started moving in response to data center demand. Retailers are building those higher expected costs into the fixed rates they’re offering you today.

Melanie Bayley, CEO of Energex Partners, an Alberta firm that advises on large-scale energy infrastructure, said it plainly: “If you can imagine our demand suddenly doubled — and the market is based on supply and demand economics — you know what that’s going to do to the price.”

There’s also an upstream effect I haven’t seen discussed much, probably because it requires knowing how the gas industry actually works. All these new turbines being built for data centers need fuel. That fuel is Alberta natural gas. More industrial demand for gas puts upward pressure on gas prices. The cheap local gas that has quietly been one of the genuine perks of living in this province could start getting bid up by the same boom the government is promoting as purely good news.

The government has tried to address the consumer concern — new legislation requires data centers to pay for their own transmission upgrades, and there’s a new levy on large facilities to fund grid improvements. Those are real measures. But in a fully deregulated market, the government’s ability to hold your electricity price down against a potential doubling of demand is limited. They can soften it. They can’t stop it.

A U.S. analysis estimated data center load growth could push residential electricity bills up roughly 1% per year through 2032. Alberta’s situation is more concentrated and faster-moving than the American average. I’d be genuinely surprised if we did better than that.

Enter the Sun

I own a solar company. I want you to know that going into this next section, because it’s relevant and because I think you can tell when somebody’s trying to hide their angle and it’s annoying.

That said: the case for solar in Alberta right now isn’t really about environmentalism, though the environmental case is fine too. It’s about inflation-proofing a portion of your energy costs during a period when those costs have a specific, identifiable reason to rise. Solar panels, properly understood, are an asset that produces a commodity, electricity whose price you have good reason to believe is going up.

Here’s what I mean by inflation-proof asset. Once those panels are on your roof, the electricity they generate costs you nothing per kilowatt-hour. Not next year, not in fifteen years, not when the data center in Olds is drawing as much power as Edmonton and the spot market is doing something uncomfortable. The sun doesn’t renegotiate. It doesn’t participate in Alberta’s electricity futures market. Its output is free for the life of the system, which is 25 to 30 years minimum with quality equipment.

For people thinking about retirement — about what their fixed costs will look like in ten or fifteen years, that’s not a trivial thing. Locking in a significant portion of your electricity now, at today’s effective cost, is the kind of move that looks very smart if energy prices do what I think they’re going to do, and looks merely fine if I’m wrong. The asymmetry favors acting.

Alberta is, counterintuitively, one of the best provinces in the country for solar generation. Up to 320 sunny days a year in many areas. Calgary’s solar irradiance is comparable to parts of Spain, people find that hard to believe but it’s true, the cold actually helps panel efficiency. Every kilowatt of installed capacity generates 1,000 to 1,500 kilowatt-hours annually here.

A typical residential system, 5 to 10 kilowatts, runs between $12,500 and $35,000 installed. The federal interest-free loan program that used to make this easier has closed, and the provincial rebate is gone too. What remains is low-interest financing through some

Alberta municipalities under the Clean Energy Improvement Program, which attaches to your property rather than you personally, useful if you’re not planning to stay in the house forever, because it transfers with the sale. Some installers offer their own financing.

The math still works without the grants, it just takes a little longer to get there. Payback periods currently run from 6 to 12 years depending on system size, roof orientation, and your consumption pattern. After payback, you’re generating electricity for free.

Alberta’s micro-generation rules let you sell surplus power back to the grid. We use Solar Club with most of our installs, it’s a rate structure built around net billing with a feed-in tariff that pays 33.5¢/kWh for the electricity you export during peak production months, while letting you buy winter power at 8.4¢/kWh when your system is generating less than you consume. You switch rates once per billing cycle, no cost. The strategy is straightforward: be on the high rate from roughly March through October when you’re a net exporter, drop to the low rate November through February when you’re drawing from the grid. Credits from your summer surplus roll forward and routinely carry households through to December or January with zero out-of-pocket electricity costs.

That spread, selling at 30 cents, buying at under 9 cents, is what moves the numbers from “pretty good investment” to genuinely compelling. Most of the systems we install show a return on investment between 12 and 17 percent, with an internal rate of return of 9 to 11 percent. I’ll let you run your own numbers, but a 10 to 12 percent annual return on a tangible asset that also hedges your cost of living isn’t something you find everywhere.

The Punchline

My family has been moving natural gas around this province for over seventy years, back when Dief was the Chief. They’re not villains. They built something real, something that heated homes and ran industry and employed generations of people in communities that needed the work. I respect what they built. I also grew up watching that industry think about its own interests with a clarity and focus that is genuinely instructive.

Right now, the industry’s interest, and the government’s interest, is in consuming as much Alberta natural gas as possible, locally, at the highest possible value. The AI data center strategy is an elegant solution to a genuine problem: stranded resources in a landlocked province. I understand the logic. It’s actually pretty clever.

But the costs land somewhere. In a deregulated market, a meaningful portion of them land on the people paying electricity bills and heating their homes with gas. The government’s mitigation measures are real and probably insufficient. And there’s almost no public conversation about what doubling electricity demand does to the rate your retired neighbour pays to keep the lights on.

I worked this out from what I heard at a family dinner, then went looking for confirmation, and found plenty of it. The people building this understand exactly what they’re doing. I’m not sure the people who’ll be paying for it do yet.

Solar is the most accessible hedge I know of against what I think is coming. Not because panels are magic, not because I’m trying to sell you something, but because the sun is the one energy source in Alberta that nobody can bid up, legislate around, or run a pipeline through to somewhere with better margins.

Put it on your roof before the storm, not after.

Full disclosure: I own a solar installation company. My great-grandfather

Charles was deeply involved in the first natural gas co-ops in Alberta, and

the family has run a pipeline company in the province since the 1950s. The

chain of thought that became this article started in my uncle’s kitchen over

coffee, he mentioned a former employer of mine who is now building gas

turbines for data centres. I verified and expanded the thesis through

research, AESO reports, provincial legislation, and reporting from CBC,

The Narwhal, Canada’s National Observer, BetaKit, and others, but the

original insight came from that conversation. I think knowing where an idea

comes from matters. Now you do.