Copilot Prompt:

Alberta, Canada, has set a net zero 2050 target, including building space and water heating. But Alberta is what I would call a cheap-natgas, expensive-electricity-delivery, cold-climate zone. With no consumer carbon price (canceled last year by federal government), there doesn't appear to be sufficient regulatory intervention in the market to steer building owners to zero emissions. Q. what are the government intervention plans, or if you can't find any, what are the likely future interventions and technologies and fuels?

Copilot Response:

Alberta’s current policy mix for decarbonizing building heating is thin relative to its 2050 net‑zero target, and the gap you’re noticing between cheap natural gas, high electricity delivery costs, cold climate, and no consumer carbon price is very real. The available evidence shows incremental code tightening but no comprehensive plan that would reliably shift the market away from natural gas for space and water heating.

The most important takeaway: Alberta is relying almost entirely on building‑code efficiency tiers, voluntary programs, and federal industrial‑carbon‑pricing backstops—not on any direct consumer‑facing decarbonization policy for heating. newhomesalberta.ca City of Edmonton

Below is a structured map of what exists, what’s missing, and what is most likely to emerge.

1. What Alberta is doing today (confirmed interventions)

🧱 Building‑code tightening (NBC 2023 Alberta Edition)

Alberta adopted the National Building Code 2023 (Alberta Edition) and NECB 2020 with Tier 1 performance requirements effective May 1, 2024. Tier 1 is the lowest tier—essentially a modest efficiency improvement, not a fuel‑switching driver. newhomesalberta.ca City of Edmonton

• No mandatory heat‑pump readiness.

• No prohibition or disincentive for natural‑gas furnaces or water heaters.

• No announced schedule for moving to higher tiers (Tier 2–4), which would be required to materially reduce heating loads.

🏘️ Voluntary net‑zero ready demonstrations

Emissions Reduction Alberta (ERA) has funded pilot net‑zero ready home designs, but these are demonstrations, not regulatory pathways. They show technical feasibility but do not create market‑wide change. Emissions Reduction Alberta

🏙️ Municipal alignment with provincial codes

Cities like Edmonton are implementing the provincial energy code but cannot exceed it without provincial approval. Municipalities therefore lack the authority to mandate heat pumps, district energy, or zero‑emission standards. City of Edmonton

🔥 No consumer carbon price

With the federal consumer carbon price removed in Alberta, there is no price signal pushing households away from natural gas. This is the single largest missing lever.

2. What Alberta is not doing (the policy gaps)

• No provincial zero‑emission building standard or timeline.

• No fuel‑switching incentives (e.g., heat pump rebates).

• No electricity rate reform to reduce delivery charges or shift to performance‑based regulation.

• No gas‑system transition plan (e.g., managed decline, decommissioning strategy, or moratorium on new gas hookups).

• No building retrofit strategy for existing homes.

• No hydrogen blending mandate for distribution utilities.

• No district energy expansion strategy for urban cores.

This is why the market continues to default to natural gas: it is cheap, familiar, and unregulated from a carbon standpoint.

3. What interventions are most likely in the future

Given Alberta’s political economy, regulatory culture, and resource base, the most plausible future interventions fall into four categories.

3.1. Efficiency‑first tightening of building codes

Alberta will likely continue adopting higher tiers of the national code (Tier 2 → Tier 3 → Tier 4), because:

• It aligns with national harmonization.

• It avoids explicit fuel‑switching mandates.

• It reduces heating loads without forcing electrification.

This is the lowest‑friction path for the province.

3.2. Hydrogen blending into the gas grid

Alberta’s government and utilities have signaled interest in hydrogen as a way to decarbonize gas infrastructure without forcing electrification. Expect:

• 5–20% hydrogen blending pilots.

• Possible long‑term shift to dedicated hydrogen pipelines for industry, with limited residential use.

• Technical challenges: appliance compatibility, NOx emissions, and energy density.

Hydrogen blending reduces emissions only marginally unless hydrogen is produced at scale with CCS.

3.3. Carbon capture on upstream gas production

Alberta may lean heavily on upstream CCS to claim “lower‑carbon natural gas” rather than changing end‑use heating systems. This is politically aligned with the province’s industrial strategy.

3.4. Targeted electrification where economics improve

Heat pumps will eventually penetrate Alberta because:

• Cold‑climate heat pump performance continues to improve.

• Electricity decarbonization continues federally.

• Gas distribution costs will rise as the customer base shrinks.

But without incentives or carbon pricing, adoption will be slow and concentrated in:

• New builds with good envelopes.

• Rural areas with propane or oil heating.

• High‑performance custom homes.

4. What technologies and fuels are most likely to dominate by 2050

1. High‑efficiency cold‑climate heat pumps

Even in Alberta’s climate, modern variable‑speed heat pumps can outperform gas on lifecycle emissions and, eventually, cost—if electricity delivery charges are reformed or if gas rates rise due to declining throughput.

2. Hybrid heating (heat pump + gas backup)

This is the most politically and economically plausible near‑term pathway:

• Reduces emissions 40–70%.

• Avoids winter peak‑load stress on the grid.

• Allows utilities to maintain gas infrastructure longer.

3. District energy in dense urban cores

Edmonton and Calgary have viable nodes for:

• Waste‑heat recovery

• Geo‑exchange fields

• Biomass or renewable natural gas (RNG) integration

But this requires municipal authority and capital support.

4. Renewable natural gas (RNG)

RNG is scarce and expensive, but Alberta has agricultural and landfill feedstocks. It will likely be reserved for:

• Hard‑to‑electrify buildings

• Peak‑load backup

• Industrial processes

5. Hydrogen (limited residential role)

Hydrogen may play a role in:

• Industrial clusters

• Heavy transport

• Power generation
  But residential heating with pure hydrogen is unlikely to be cost‑competitive.

5. The most realistic overall pathway for Alberta

Given current policy and political constraints, Alberta’s building‑heating decarbonization will likely follow this trajectory:

1. Efficiency improvements through code tier progression.

2. Slow, market‑driven heat pump adoption in new builds and high‑performance homes.

3. Hybrid heating as a transitional norm.

4. Hydrogen blending to reduce emissions from the gas grid without forcing electrification.

5. Long‑term gas‑system contraction as economics shift and federal pressure increases.

6. Selective district energy in urban cores.

7. Upstream CCS to reduce lifecycle emissions of remaining natural gas.

This is a slower, more incremental pathway than provinces like BC or Quebec, but it is consistent with Alberta’s current policy posture.

If you want, I can map out what a credible Alberta‑specific building‑heating decarbonization plan would look like, including the regulatory levers that would actually work in a cheap‑gas, high‑delivery‑charge, cold‑climate context.

/Copilot Response

Copilot Prompt:

yes please map out what an Alberta-specific building heating decarbonization plan would look like.

Copilot Response:

You’re right at the crux of it: in Alberta, you can’t just copy‑paste a BC‑style “ban gas, push heat pumps” playbook. Cheap gas, high delivery charges, and a cold climate mean the plan has to be sequenced, hybrid, and grid‑aware, not ideological.

Here’s what a credible Alberta‑specific building‑heating decarbonization plan would look like.

1. Design principles for an Alberta plan

• Principle 1 – Respect the gas advantage (for now): Don’t pretend gas isn’t cheap. Use policy to bend the economics over time, not flip them overnight.

• Principle 2 – Grid‑first, not heat‑pump‑first: Any electrification plan has to be synchronized with transmission, distribution, and winter peak planning.

• Principle 3 – Hybrid, not binary: Treat “heat pump + gas backup” as a core transition technology, not a compromise.

• Principle 4 – Cold‑climate realism: Envelope performance and load reduction are non‑negotiable; otherwise, electrification is a political and technical non‑starter.

• Principle 5 – Use federal pressure and money: Lean on federal codes, funding, and industrial carbon pricing while keeping provincial political ownership.

2. Clear targets and segmentation

2.1. Targets

• 2050: Net‑zero emissions from building space and water heating.

• 2030 waypoint:

  • New buildings: 80–90% of new floor area “zero‑emission ready” (heat‑pump capable, very low loads).

  • Existing buildings: 20–30% of stock with at least one major decarbonization measure (envelope, heat pump, hybrid, or district energy connection).

2.2. Segmentation

• Segment A – New urban residential (Edmonton, Calgary, Airdrie, etc.).

• Segment B – Existing urban residential.

• Segment C – Rural and small communities.

• Segment D – Large commercial/institutional (schools, hospitals, campuses).

• Segment E – Industrial‑adjacent buildings (where waste heat or hydrogen may be available).

Each segment gets a different mix of tools and technologies.

3. Pillar 1 – Building codes and performance standards

3.1. Code tier roadmap

• Now–2026: Lock in a public schedule to move from Tier 1 → Tier 2 → Tier 3 of the national energy code, with:

  • Mandatory blower‑door testing for new homes.

  • Minimum envelope performance (U‑values, airtightness) that make heat pumps viable.

• 2027–2030: Introduce a “Net‑Zero Ready Tier” for new large buildings and subdivisions:

  • Very low heating loads.

  • Heat‑pump‑ready electrical capacity.

  • No new oil/propane systems; gas allowed only as backup.

3.2. Zero‑emission performance standard (not fuel bans)

Instead of banning gas, Alberta could adopt a performance‑based standard:

• For new buildings (by ~2030):

  • Space + water heating emissions intensity cap (kg CO₂/m²·year).

  • Builders can comply via:

    • Heat pumps (air‑source or geo‑exchange).

    • Hybrid systems (heat pump + high‑efficiency gas).

    • District energy connections.

• For major retrofits (post‑2030):

  • When a building triggers a major permit (e.g., >50% of envelope or HVAC replaced), it must meet a tighter emissions intensity cap.

This keeps flexibility while forcing the design to consider emissions, not just capital cost.

4. Pillar 2 – Gas system transition and hybrid heating

4.1. Hybrid as the default transition

Make hybrid heating the “Alberta standard” for the next 10–20 years:

• Policy levers:
  
  

  • Require that any new gas furnace installation (above a certain size) be paired with a cold‑climate heat pump sized for shoulder seasons.

  • Offer capital rebates for the heat pump portion only.

  • Allow utilities to treat hybrid adoption as a demand‑side management (DSM) resource.

• Outcome:
  
  

  • Gas use drops 40–70% per home.

  • Winter peak on the grid is moderated.

  • Customers keep a familiar backup, reducing perceived risk.

4.2. Gas utility regulation and managed decline

• No‑regrets steps:
  
  

  • Require gas utilities to file “Net‑Zero Network Plans”:

    • Forecasted throughput decline.

    • High‑cost, low‑density segments for early decommissioning.

    • Strategy for avoiding stranded assets.

  • Allow rate‑base recovery for:

    • Targeted line decommissioning.

    • Customer transition programs (e.g., incentives to switch to hybrid or full electric when lines are removed).

• Hydrogen and RNG:
  
  

  • Cap hydrogen blending in residential networks at a modest level (e.g., 5–10%) unless appliances and safety standards evolve.

  • Reserve RNG for:

    • Hard‑to‑electrify buildings.

    • Peak backup.

    • Remote communities.

The key is to stop planning the gas grid as if demand will grow forever.

5. Pillar 3 – Electricity pricing, grid planning, and rate design

5.1. Rate reform to make heat pumps viable

Right now, high delivery charges kill heat‑pump economics. Alberta could:

• Introduce a “clean heating” rate class:

  • Lower fixed charges.

  • Time‑of‑use (TOU) or critical‑peak pricing to reward off‑peak operation.

• Enable demand‑response for heat pumps:

  • Utilities can briefly curtail or modulate heat pumps during extreme peaks, with customer compensation.

• Align DSM with electrification:

  • Treat heat pumps and envelope upgrades as system resources in planning, not just customer gadgets.

5.2. Grid planning with explicit heating scenarios

• Require the AESO and distribution utilities to:

  • Model multiple heating pathways (status quo gas, hybrid, high electrification).

  • Publish capacity and cost implications.

  • Use these scenarios to guide:

    • Transmission build‑out.

    • Local distribution upgrades.

    • Siting of storage and flexible generation.

This avoids the “oops, we electrified heating and now the grid is stressed” problem.

6. Pillar 4 – Targeted incentives and finance

6.1. New builds

• Builder‑focused incentives:

  • Bonuses for subdivisions built to Net‑Zero Ready Tier with:

    • Heat‑pump‑ready design.

    • District energy where feasible.

  • Fast‑track permitting and reduced fees for compliant projects.

6.2. Existing homes

• Stacked retrofit packages:
  
  

  • Tier 1 package: Envelope + smart thermostat (no fuel switch).

  • Tier 2 package: Envelope + cold‑climate heat pump (hybrid with existing gas).

  • Tier 3 package: Deep retrofit + full electrification (or district energy connection).

• Finance tools:
  
  

  • On‑bill financing through utilities (paid back via energy savings).

  • Property‑linked financing (PACE‑style) where municipalities are willing.

  • Use federal/provincial funds to buy down interest rates or provide partial grants.

6.3. Large commercial and institutional

• Require energy and emissions benchmarking for large buildings.

• Offer performance‑based incentives:

  • Pay per verified tonne of CO₂ reduced from baseline.

• Prioritize:

  • Heat‑recovery chillers.

  • Geo‑exchange fields under parking lots or campuses.

  • District energy in dense nodes.

7. Pillar 5 – District energy and geo‑exchange hubs

7.1. Urban cores and campuses

• Identify priority zones in Edmonton, Calgary, Red Deer, etc., where:

  • Load density is high.

  • Waste heat or geo‑exchange potential exists.

• Support:

  • Municipal or utility‑led district energy corporations.

  • Capital grants or low‑cost loans for:

    • Central plants (heat pumps, biomass, waste heat).

    • Distribution piping.

• Require new large buildings in these zones to be “district‑ready”:

  • Space for heat‑exchanger rooms.

  • Piping stubs and design allowances.

7.2. Industrial‑adjacent opportunities

• Where industrial facilities produce low‑grade waste heat:

  • Encourage heat‑sharing networks to nearby residential or commercial clusters.

  • Use industrial carbon‑pricing revenues to co‑fund infrastructure.

8. Pillar 6 – Federal alignment and carbon pricing reality

Even if Alberta doesn’t want a consumer carbon price, a realistic plan would:

• Leverage federal funds for:

  • Heat pump programs.

  • Deep retrofits.

  • District energy and geo‑exchange.

• Use industrial carbon pricing and CCS to:

  • Lower upstream emissions from gas production.

  • Claim lower lifecycle emissions for the remaining gas used in buildings.

• Keep the door open to:

  • A future, more politically acceptable carbon signal (e.g., a “clean heat standard” or feebate rather than a visible fuel tax).

9. How this actually plays out in Alberta’s context

If you put all of this together, a plausible Alberta trajectory looks like:

1. 2025–2030:
   
   

   • Code tightening + hybrid incentives.

   • First district energy and geo‑exchange hubs.

   • Gas utilities start filing net‑zero plans.

2. 2030–2040:
   
   

   • New buildings mostly net‑zero ready, many with heat pumps or hybrid systems.

   • Existing stock sees widespread hybrid adoption and envelope upgrades.

   • Selective gas line decommissioning in low‑density or high‑cost areas.

3. 2040–2050:
   
   

   • Full electrification or district energy in urban cores.

   • Gas use concentrated in hybrids, rural areas, and niche applications, with upstream CCS and some RNG/hydrogen.

   • Overall building‑heating emissions approach net zero.

If you’d like, we can zoom into one segment—for example, “existing single‑family homes in Airdrie/Calgary”—and sketch what a concrete 2025–2035 policy + technology pathway would look like at the level of actual equipment choices, bills, and grid impacts.

/Copilot Response

Copilot Prompt:

yes please zoom into two segments in Airdrie/Calgary: a) existing single-family homes b) existing low-rise wood-framed boiler heated MURBs- and sketch what a concrete 2025-2035 policy + technology path would look like at level of actual equipment choices, bills, grid impacts for each.

Copilot Response:

You picked the two segments that really decide whether this works or not. Let’s treat them like mini‑case studies and walk them from 2025 to 2035 in a way that’s actually plausible in Airdrie/Calgary: what gets installed, what happens to bills, and what the grid “feels”.

A. Existing single‑family gas‑furnace homes

Think: 1990s–2010s detached house in Airdrie/Calgary, 150–220 m², decent but not great envelope, 60–100k BTU gas furnace, gas DHW, typical Alberta bill profile (gas cheap, electricity dominated by fixed/delivery).

1. 2025–2027: “No‑regrets” envelope + hybrid‑ready

Policy levers that would move this segment

• Code/standard:

  • Furnace replacement rule: any new furnace ≥60k BTU must be “hybrid‑ready” (electrical panel capacity, outdoor pad, control wiring).

• Incentives:

  • Envelope rebates: attic top‑up, basic air‑sealing, smart thermostat.

  • Panel upgrade support: partial rebate for going from 100A → 150/200A if needed for future heat pump.

• Finance:

  • On‑bill financing for envelope + panel work.

Typical equipment choices

• Stay with gas furnace (mid or high efficiency) at end of life, but:

  • Attic insulation improved (e.g., R‑20 → R‑40+).

  • Air‑sealing (leakage down maybe 20–30%).

  • Smart thermostat with basic scheduling.

  • Electrical panel sized to accept a future 2–3 ton cold‑climate heat pump.

Bill impacts (directional)

• Gas use: down ~10–20% from envelope + controls.

• Electricity: small increase from fans/controls, but negligible vs fixed charges.

• Net bill: slightly lower, but not transformative—this phase is about preparing the house.

Grid impacts

• Peak demand: almost unchanged.

• Energy use: slightly up from more fan runtime, but trivial.

• System value: the grid is being quietly prepared for later heat‑pump load without big shocks.

2. 2027–2031: Hybrid becomes the “default” replacement

This is where things actually start to bend the curve.

Policy levers

• Hybrid requirement or strong nudge:

  • When a furnace is replaced, hybrid is the default: a cold‑climate air‑source heat pump sized for ~60–80% of design load + a smaller gas furnace for peaks.

• Rebates:

  • Heat pump rebate (capital buy‑down).

  • Bonus if combined with DHW upgrade (e.g., heat pump water heater or high‑efficiency gas).

• Rate design:

  • “Clean heating” electricity rate with lower fixed charges and mild time‑of‑use to reward off‑peak operation.

Typical equipment choices

• Space heating:

  • 2–3 ton cold‑climate heat pump (variable speed, COP >2 at −15°C).

  • Smaller gas furnace (e.g., 40–60k BTU) as backup/peak.

• DHW:

  • Many will stay on gas tank initially; some will adopt heat pump water heaters if incentives are good.

How the system actually runs

• Shoulder seasons (−5°C and warmer):

  • Heat pump does almost all heating.

• Colder periods (−5 to −20°C):

  • Heat pump still runs, but gas kicks in for peaks or defrost.

• Extreme cold snaps (<−25°C):

  • Gas carries most of the load; heat pump may idle or run minimally.

Bill impacts (directional, assuming today’s price structure)

• Gas use:

  • Down ~40–60% for space heating (more if envelope was improved earlier).

• Electricity use:

  • Up significantly in winter (heat pump), but:

    • If fixed/delivery charges are moderated for “clean heating” customers, the marginal kWh cost can be competitive.

• Net annual bill:

  • With no rate reform, many households see similar or slightly higher total bills but with lower emissions.

  • With targeted rate reform + rebates, you can get to bill‑neutral or modest savings for a large share of homes.

Grid impacts

• Winter peak:

  • Hybrid design + demand‑response (utility can briefly reduce heat‑pump output during extreme peaks) keeps the incremental peak manageable.

• Energy:

  • Winter electricity consumption rises, but gas still covers the worst hours.

• Planning:

  • AESO and local DSOs can see this coming and plan feeders/transformers accordingly.

3. 2031–2035: Selective full electrification and gas line contraction

By early 2030s, some neighbourhoods and customers are ready to go further.

Policy levers

• Targeted “gas‑off” zones:

  • In areas where gas mains are old/expensive to maintain, utilities offer enhanced incentives to go full electric when equipment turns over.

• Deep retrofit packages:

  • Envelope + full heat pump + heat pump water heater, with stacked grants + low‑interest finance.

• Gas utility net‑zero plans:

  • Identify segments for early decommissioning and use rate‑base recovery to fund customer transitions.

Typical equipment choices

• Space heating:

  • Larger or dual‑stage cold‑climate heat pump sized closer to full design load.

• DHW:

  • Heat pump water heater or connection to a local low‑temperature district loop where available.

• Backup:

  • In some cases, electric resistance or small gas fireplace as emergency backup.

Bill impacts

• Gas bill:

  • Approaches zero where gas is fully disconnected.

• Electricity bill:

  • Higher variable component, but:

    • No gas fixed charges.

    • Better rate design (TOU, demand response credits).

• Net:

  • In targeted zones, with good envelope and modern heat pumps, total annual energy cost can be similar or slightly lower than a 2025 gas‑only baseline, with much lower emissions.

Grid impacts

• Local peaks:

  • Higher in fully electrified pockets; mitigated by:

    • Good envelopes.

    • Smart controls (pre‑heating, demand response).

• System‑wide:

  • Still a mix: many hybrids, some full electric, some legacy gas.

  • The grid has had a decade to adapt.

B. Existing low‑rise, wood‑framed, boiler‑heated MURBs

Think: 3–4 storey walk‑ups or small elevator buildings, 1970s–2000s, central gas boiler + radiators/baseboards, often poor envelope, sometimes separate gas DHW. These are emissions‑dense and politically sensitive (renters).

1. 2025–2028: Benchmarking, controls, and “no‑regrets” boiler upgrades

Policy levers

• Mandatory benchmarking:

  • Large MURBs must report energy use and emissions annually.

• Minimum boiler efficiency at replacement:

  • Condensing boilers only, with proper return‑temperature design.

• Incentives:

  • Controls + distribution upgrades: TRVs, balancing, pumps, basic envelope (common‑area air‑sealing, roof insulation).

• Finance:

  • Low‑interest loans tied to the building, not the owner, to avoid rent shock.

Typical equipment choices

• Boiler plant:

  • Old atmospheric boiler → condensing boiler with outdoor reset and variable‑speed pumps.

• Distribution:

  • TRVs on radiators, better zoning, night setback.

• Envelope:

  • Roof insulation, stairwell/parkade air‑sealing, maybe window replacements in worst cases.

Bill impacts

• Gas use:

  • Down ~15–30% from better boiler + controls + modest envelope.

• Electricity:

  • Slightly up from pumps/controls, but small relative to gas savings.

• Net:

  • Lower operating costs, easier to justify to owners.

Grid impacts

• Minimal at this stage—this is still a gas‑dominant system.

2. 2028–2032: Central heat‑pump integration and “low‑temp” hydronic

This is the big technical pivot: turning these buildings into low‑temperature hydronic systems that can be fed by heat pumps.

Policy levers

• Performance‑based standard for MURBs:

  • By, say, 2032, MURBs above a certain size must meet a space‑heating emissions intensity target.

• Capital incentives:

  • Grants/loans for central air‑to‑water or water‑to‑water heat pumps tied into the existing hydronic loop.

• District energy zones:

  • In dense areas, encourage connection to district geo‑exchange or waste‑heat networks instead of individual boilers.

Typical equipment choices

• Option 1 – Central air‑to‑water heat pump + gas boiler backup:

  • Install a central heat pump that supplies 35–45°C water for most of the season.

  • Keep a condensing gas boiler for peak loads and very cold days.

  • May require radiator upgrades or fan‑coil units if existing emitters can’t deliver enough heat at lower temps.

• Option 2 – Connect to district energy (where available):

  • Building heat exchanger + internal distribution upgrades.

  • Central plant (heat pumps, waste heat, biomass) is off‑site.

How the system runs

• Shoulder seasons:

  • Heat pump covers nearly all heating; boiler mostly idle.

• Cold periods:

  • Heat pump runs continuously; boiler trims peaks or covers defrost gaps.

• Extreme cold:

  • Boiler dominates, but these hours are a small fraction of the year.

Bill impacts

• Gas use:

  • Down ~40–70% for space heating.

• Electricity:

  • Up significantly at the building level (central heat pump), but:

    • Spread across many units.

    • Can be partially offset by favourable commercial rates or specific “clean heating” tariffs.

• Net:

  • For owners: lower total energy cost is achievable if incentives cover part of the capital and if the building was due for boiler replacement anyway.

  • For tenants: ideally neutral or modestly lower rents + utilities, depending on how costs are passed through.

Grid impacts

• Local feeders:

  • Noticeable new winter load where many MURBs adopt central heat pumps.

• System‑wide:

  • Still manageable if:

    • Adoption is phased.

    • AESO includes this in planning.

    • Demand response (e.g., slight temperature setbacks during peaks) is enabled.

3. 2032–2035: Deep retrofits and partial gas phase‑down

By early/mid‑2030s, the worst‑performing MURBs either get deep retrofits or become candidates for redevelopment.

Policy levers

• Tiered performance standard:

  • Stricter emissions intensity for MURBs by 2035, with compliance pathways: deep retrofit, district energy, or hybrid central plant.

• Targeted capital programs:

  • Deep retrofit funds for low‑income or affordable housing MURBs.

• Gas network planning:

  • Identify clusters of MURBs where gas mains can be downsized or eventually removed as buildings electrify or connect to district energy.

Typical equipment choices

• Deep retrofit path:

  • Exterior insulation, high‑performance windows, airtightness upgrades.

  • Central heat pump sized for most of the load, with small boiler or electric resistance as backup.

• District energy path:

  • Full reliance on low‑carbon district heat; gas boiler removed or kept as emergency backup only.

Bill impacts

• Gas:

  • Approaches zero for fully electrified/district‑connected buildings.

• Electricity/district charges:

  • Higher than today’s electricity alone, but:

    • No gas fixed charges.

    • Much lower total kWh/BTU demand due to deep envelope work.

• Net:

  • For well‑executed deep retrofits, total annual energy cost per unit can be similar or lower than a 2025 baseline, with far better comfort and resilience.

Grid impacts

• Urban nodes:

  • Higher winter loads in MURB‑dense areas, but:

    • District energy and geo‑exchange can shift much of the load to large, efficient central plants.

    • Storage (thermal or electrical) can smooth peaks.

• Gas system:

  • Lower throughput in urban cores, enabling targeted decommissioning of some mains.

Pulling it together

For both segments, the credible 2025–2035 path in Airdrie/Calgary isn’t “flip to all‑electric”; it’s:

• 2025–2028: Prep the stock—envelopes, controls, panels, better boilers.

• 2028–2032: Make hybrid the norm for single‑family and central heat pumps + boilers the norm for MURBs.

• 2032–2035: Start selective full electrification/district energy and gas line contraction where it’s cheapest and most logical.

If you want to go one level deeper, we can pick a specific archetype—say, a 1998 Airdrie detached with a 90% gas furnace and a 24‑suite boiler‑heated walk‑up—and sketch rough annual GJ/kWh flows and bill deltas across those three phases.

/Copilot Response

Copilot Prompt:

yes please go deeper on 2 specific archetypes a) a 1998 Airdrie detached with a 90% gas furnace and b) a 80‑suite boiler‑heated MURB—and sketch rough annual GJ/kWh flows and bill deltas across those three phases.

Copilot Response:

You get a much clearer picture when we anchor this to two concrete Alberta archetypes and walk them through three phases (2025–2035) with actual GJ/kWh flows, equipment choices, and bill deltas. These are illustrative but realistic for Airdrie/Calgary climate, housing stock, and utility pricing structures.

1) Archetype A — 1998 Airdrie Detached

150–200 m², 2×6 walls, R‑20 attic (original), ACH50 ≈ 5–7, 90% gas furnace (80–100k BTU), gas DHW, typical Alberta bills.

Baseline (2025)

• Space heating load: ~80–100 GJ/yr

• DHW: ~15–20 GJ/yr

• Total gas: ~95–120 GJ/yr

• Electricity: ~6,000–7,500 kWh/yr (mostly fixed charges + appliances)

Annual bills (directional):

• Gas: ~$900–$1,200

• Electricity: ~$1,800–$2,200

• Total: ~$2,700–$3,400

Phase 1 (2025–2027) — Envelope + Hybrid‑Ready Prep

Attic top‑up, air‑sealing, smart thermostat, panel upgrade.

Energy flows after Phase 1

• Space heating load: drops ~10–20% → 65–85 GJ/yr

• DHW: unchanged → 15–20 GJ/yr

• Total gas: 80–105 GJ/yr

• Electricity: +200–300 kWh/yr (fans, controls)

Bills

• Gas: down ~$100–$200/yr

• Electricity: up ~$30–$50

• Net: ~$70–$150 savings/yr

Grid impact

• Essentially unchanged peak; slightly higher shoulder‑season fan runtime.

Phase 2 (2027–2031) — Hybrid Heating Becomes Standard

Install 2–3 ton cold‑climate heat pump + smaller gas furnace.

Energy flows after Phase 2

Assume heat pump covers ~60–70% of annual space heating load.

• Space heating:

  • Heat pump: ~40–55 GJ delivered → ~6,000–8,000 kWh

  • Gas backup: ~20–30 GJ

• DHW: still gas → 15–20 GJ

• Total gas: 35–50 GJ/yr (down from 95–120)

• Total electricity: baseline 6,500 + heat pump 7,000 ≈ 13,000–15,000 kWh/yr

Bills (assuming no rate reform)

• Gas: ~$350–$550

• Electricity: ~$2,600–$3,000

• Total: ~$3,000–$3,500 (slightly higher than baseline)

Bills (with “clean heating” rate class)

• Lower fixed charges + mild TOU

• Electricity: ~$2,200–$2,500

• Total: ~$2,600–$3,000 (bill‑neutral or modest savings)

Grid impact

• Winter peak: +1–2 kW per home during heat pump operation

• But hybrid design prevents extreme‑cold peaks from stacking.

Phase 3 (2031–2035) — Selective Full Electrification

Only in targeted zones or when gas mains are due for decommissioning.

Energy flows after Phase 3

Assume envelope upgrades + larger heat pump sized for ~90% of design load.

• Space heating:

  • Heat pump: ~60–70 GJ delivered → ~10,000–12,000 kWh

  • Electric resistance backup: ~2–5 GJ → ~600–1,400 kWh

• DHW: heat pump water heater → 1,500–2,000 kWh

• Total electricity: 18,000–20,000 kWh/yr

• Total gas: 0 GJ (if disconnected)

Bills

• Electricity: ~$2,800–$3,200 (with clean‑heat rate)

• Gas: $0

• Total: ~$2,800–$3,200 (similar to baseline, but zero emissions)

Grid impact

• Winter peak: +3–4 kW per home

• Manageable if adoption is phased and demand response is active.

2) Archetype B — 80‑Suite Low‑Rise Boiler‑Heated MURB

1970s–1990s wood‑frame, central gas boiler, radiators/baseboards, poor envelope, 80 suites, 4–5 storeys.

Baseline (2025)

• Space heating: ~1.2–1.6 GJ/m²·yr → 1,200–1,600 GJ/yr

• DHW: ~300–400 GJ/yr

• Total gas: 1,500–2,000 GJ/yr

• Electricity: ~150,000–200,000 kWh/yr (common areas + pumps + suites)

Annual bills:

• Gas: ~$15,000–$22,000

• Electricity: ~$25,000–$35,000

• Total: ~$40,000–$55,000

Phase 1 (2025–2028) — Controls + Condensing Boiler + Light Envelope

TRVs, balancing, outdoor reset, roof insulation, stairwell air‑sealing.

Energy flows after Phase 1

• Space heating: down 15–25% → 900–1,300 GJ/yr

• DHW: unchanged → 300–400 GJ

• Total gas: 1,200–1,700 GJ/yr

• Electricity: +5,000–10,000 kWh (pumps/controls)

Bills

• Gas: down ~$3,000–$5,000

• Electricity: up ~$500–$1,000

• Net: ~$2,500–$4,000 savings/yr

Grid impact

• Minimal; still gas‑dominant.

Phase 2 (2028–2032) — Central Air‑to‑Water Heat Pump + Boiler Backup

Shift to low‑temperature hydronic (35–45°C).

Energy flows after Phase 2

Assume heat pump covers ~60% of space heating load.

• Space heating:

  • Heat pump: ~500–800 GJ delivered → ~140,000–220,000 kWh

  • Gas boiler: ~300–500 GJ

• DHW: still gas → 300–400 GJ

• Total gas: 600–900 GJ/yr (down from 1,500–2,000)

• Total electricity: baseline 180,000 + heat pump 180,000 ≈ 330,000–400,000 kWh/yr

Bills

• Gas: ~$6,000–$9,000

• Electricity: ~$45,000–$55,000

• Total: ~$51,000–$64,000

BUT with incentives + commercial clean‑heat tariff:

• Electricity: ~$35,000–$45,000

• Total: ~$41,000–$54,000 (similar to baseline, but emissions down ~50–60%)

Grid impact

• Winter peak: +50–100 kW for the building

• Manageable if sequenced across neighbourhoods.

Phase 3 (2032–2035) — Deep Retrofit or District Energy

Envelope + full heat pump or connection to low‑temp district loop.

Energy flows after Phase 3

Assume deep envelope retrofit (30–40% load reduction) + large heat pump.

• Space heating:

  • Heat pump: ~700–900 GJ delivered → ~200,000–260,000 kWh

  • Backup (boiler or electric): ~50–100 GJ

• DHW: heat pump or district → ~50,000–80,000 kWh

• Total electricity: 300,000–350,000 kWh/yr

• Total gas: 0–150 GJ (depending on backup strategy)

Bills

• Electricity: ~$40,000–$50,000

• Gas: $0–$1,500

• Total: ~$40,000–$52,000 (similar to baseline, but near‑zero emissions)

Grid impact

• Winter peak: +100–150 kW

• District energy can cut this by 50–70% by shifting load to central plants.

(see table below)

The Alberta‑specific insight

Both archetypes show the same pattern:

• Phase 1: cheap, low‑disruption efficiency

• Phase 2: hybridization (heat pump + gas) cuts emissions 50–60% with manageable grid impact

• Phase 3: selective full electrification or district energy achieves near‑zero emissions without blowing up bills or the grid—but only where envelope and timing are right

If you want, I can now build a full Alberta‑specific decarbonization curve for these two archetypes (emissions vs. time, cost vs. time, grid load vs. time) or map policy levers to each phase in a way that would actually work in Airdrie/Calgary’s economics.

/Copilot Response

Copilot Prompt:

yes please build a full Alberta‑specific decarbonization curve for these two archetypes (emissions vs. time, cost vs. time, grid load vs. time) and map policy levers to each phase in a way that would actually work in Airdrie/Calgary’s economics. 

Copilot Response:

You’re basically designing AirdrieZero’s “storyboard” for two anchor building types. Let’s turn what we’ve done into curves in words: how emissions, cost, and grid load move from 2025–2035—and which levers make each bend actually happen in Alberta economics.

1. Archetype A – 1998 Airdrie detached (gas furnace)

1.1 Emissions curve (2025–2035)

• 2025 baseline:

  • ~95–120 GJ gas/yr → high emissions, flat trajectory if nothing changes.

• Phase 1 (2025–2027):

  • Envelope + controls → ~10–20% drop in space‑heating gas.

  • Curve: gentle downward slope (say −0.5–1%/yr).

• Phase 2 (2027–2031):

  • Hybrid heat pump + smaller gas furnace → ~50–60% cut in space‑heating gas.

  • Curve: visible “kink” downward as hybrid adoption ramps (e.g., 10–15% of stock per year).

• Phase 3 (2031–2035):

  • Selective full electrification in targeted zones → ~90–100% reduction vs baseline for those homes.

  • Curve: continues down but more slowly, because only a subset fully electrifies; system‑wide average maybe −70–80% by 2035 for this archetype if policy is strong.

Shape:
Flat → slight decline → sharp drop with hybrid → slower approach toward near‑zero as full electrification spreads selectively.

1.2 Cost curve (household energy bills)

• 2025 baseline:

  • ~$2,700–$3,400/yr.

• Phase 1:

  • Slight savings from envelope (~$70–$150/yr).

  • Curve: small dip.

• Phase 2 (no rate reform):

  • Hybrid raises electricity, cuts gas → net slightly higher (~+$100–$300/yr).

  • Curve: small bump up.

• Phase 2 (with “clean heat” rate + rebates):

  • Bills roughly flat or slightly down vs baseline.

  • Curve: flat or shallow downward.

• Phase 3:

  • Full electric, no gas fixed charges, good envelope → similar or slightly lower total vs 2025 baseline.

  • Curve: back to baseline or a bit below.

Shape (with good policy):
Small dip → flat through hybrid → ends near or slightly below starting point, while emissions fall steeply.

1.3 Grid load curve (per‑home winter peak)

• 2025 baseline:

  • ~1–2 kW winter peak (fans, appliances; heating mostly gas).

• Phase 1:

  • Essentially unchanged.

• Phase 2 (hybrid):

  • Heat pump adds ~1–2 kW winter peak, but gas still covers extremes.

  • Curve: step up to ~3–4 kW, then stable.

• Phase 3 (full electric):

  • Heat pump sized for near full load → ~3–4 kW incremental vs baseline.

  • Curve: another step up to ~4–5 kW, but only for a subset of homes.

System view:
If hybrids dominate and full electrification is targeted, the average peak per home rises moderately, not catastrophically.

1.4 Policy levers that actually work in Airdrie/Calgary

Phase 1 – Prep (2025–2027)

• Rebates: attic insulation, air‑sealing, smart thermostats.

• On‑bill financing: for envelope + panel upgrades.

• Code/standard: furnace replacements must be “hybrid‑ready” (panel capacity, outdoor pad, controls).

Phase 2 – Hybrid as default (2027–2031)

• Incentives: capital rebates for cold‑climate heat pumps when replacing furnaces.

• Rate design: “clean heating” tariff—lower fixed charges, mild TOU.

• Utility DSM: treat hybrids as demand‑side resources; pay for demand response.

Phase 3 – Targeted full electrification (2031–2035)

• Gas network planning: identify high‑cost mains; offer enhanced incentives to go all‑electric when those mains are retired.

• Deep retrofit packages: stacked grants + low‑interest loans for envelope + full heat pump + HPWH.

• Regulatory support: allow gas utilities to recover decommissioning + transition costs in rate base.

2. Archetype B – 80‑suite boiler‑heated MURB

2.1 Emissions curve (2025–2035)

• 2025 baseline:

  • 1,500–2,000 GJ gas/yr → very high emissions.

• Phase 1 (2025–2028):

  • Condensing boiler + controls + light envelope → ~15–25% reduction.

  • Curve: noticeable but modest downward slope.

• Phase 2 (2028–2032):

  • Central air‑to‑water heat pump + boiler backup → ~50–60% reduction vs baseline.

  • Curve: strong downward kink as central plants are upgraded.

• Phase 3 (2032–2035):

  • Deep retrofit or district energy → ~80–95% reduction.

  • Curve: approaches near‑zero for buildings that fully commit.

Shape:
Steady decline → big drop with central heat pumps → flattening near net‑zero as deep retrofits/district energy roll out.

2.2 Cost curve (building energy bills)

• 2025 baseline:

  • ~$40,000–$55,000/yr.

• Phase 1:

  • Net savings ~$2,500–$4,000/yr from better boilers + controls.

  • Curve: clear downward step.

• Phase 2 (no tariff change):

  • Gas down, electricity up → total could rise slightly.

  • Curve: small bump back up.

• Phase 2 (with clean‑heat commercial tariff + incentives):

  • Total similar to baseline or slightly lower.

  • Curve: stays near Phase 1 level.

• Phase 3:

  • Deep envelope + efficient heat pumps/district → similar or lower total vs 2025 baseline.

  • Curve: ends at or below starting point.

Shape (with good policy):
Down in Phase 1 → flat in Phase 2 → flat or slightly down in Phase 3, while emissions plunge.

2.3 Grid load curve (per‑building winter peak)

• 2025 baseline:

  • ~30–50 kW winter peak (common loads; heating mostly gas).

• Phase 1:

  • Little change.

• Phase 2:

  • Central heat pump adds ~50–100 kW winter peak.

  • Curve: step up to ~80–150 kW.

• Phase 3:

  • Deep retrofit reduces load; district energy can shift electric load off‑site.

  • Curve:

    • For standalone central HP: stays ~80–150 kW but with better load factor.

    • For district: building peak drops back toward baseline; central plant sees the load instead.

System view:
MURBs are chunky loads—planning needs to anticipate clusters of these upgrades and use district/geo‑exchange where density is high.

2.4 Policy levers that fit Alberta economics

Phase 1 – Low‑cost efficiency (2025–2028)

• Mandatory benchmarking: energy/emissions reporting for large MURBs.

• Boiler standards: condensing only at replacement, with proper design.

• Incentives: TRVs, controls, balancing, roof insulation, stairwell/parkade air‑sealing.

• Finance: low‑interest loans tied to the building, not the owner.

Phase 2 – Central heat pumps + boiler backup (2028–2032)

• Performance standard: emissions intensity target for MURBs by ~2032.

• Capital support: grants/loans for central air‑to‑water or water‑to‑water heat pumps.

• Tariff: commercial “clean heat” rate to keep operating costs near baseline.

• District energy zoning: identify priority nodes in Calgary/Edmonton for MURB clusters.

Phase 3 – Deep retrofit / district energy (2032–2035)

• Tiered standard: tighter emissions cap by 2035 with clear compliance pathways.

• Deep retrofit funds: especially for affordable/low‑income MURBs.

• Gas network planning: coordinate building transitions with gas main downsizing/retirement.

• District energy authorities: municipal or utility entities with access to low‑cost capital.

3. How this plays into an AirdrieZero narrative

For both archetypes, your decarbonization curves share the same logic:

• Emissions: big drops in Phase 2 (hybrid/central HP), then asymptotic approach to net‑zero in Phase 3.

• Costs: small dip (Phase 1), flat with good rate design (Phase 2), similar or slightly lower than baseline (Phase 3).

• Grid: moderate, manageable increases in winter peak—kept in check by hybridization, phasing, and district energy.

If you want, next step could be:

• turn these into simple charts (three curves per archetype) and a one‑page “AirdrieZero Buildings Pathway” graphic you can drop straight into your Google Site.

/Copilot Response