Emissions, Methane and Carbon Capture in Alberta's Oil Industry

Where Alberta's emissions come from

Greenhouse gases (GHGs) are counted in carbon dioxide equivalent (CO₂e), which converts other gases such as methane into the amount of CO₂ that would cause the same warming over 100 years. Canada's official count is the National Inventory Report (NIR), prepared each year by Environment and Climate Change Canada (ECCC) under the United Nations climate treaties. The 2026 edition, released in April 2026, covers the years 1990 to 2024 ^[12][1].

Nationally, emissions were 685 Mt in 2024, 10 per cent below 2005. The oil and gas sector emitted 208 Mt, about 30 per cent of the total, making it the country's largest emitting sector. Oil and gas emissions peaked at 230 Mt in 2014 and have fallen about 9.6 per cent since ^[1].

Alberta is the largest emitting province: 260.1 Mt in 2024, compared with 251.2 Mt in 2005 and a peak of 293.6 Mt in 2014 ^[2]. ECCC explains the modest rise since 2005 as the expansion of oil and gas operations, offset by the closure of coal-fired power plants ^[1]. Alberta's electricity emissions fell from 47.6 Mt in 2005 to 17.4 Mt in 2024 after the last coal plant switched to natural gas in June 2024 ^[2][7].

The oil and gas breakdown

The NIR splits oil and gas into subsectors. The table shows Alberta's emissions from each over time.

Source: ECCC 2026 inventory data file for Alberta, rounded, so rows may not add exactly ^[2].

Three patterns stand out:

• Oil sands growth. In situ emissions rose five-fold after 2005 as steam-based production expanded ^[2]. In situ wells burn natural gas to make steam ^[13], mines use fuel for haul fleets and heat for processing ^[3], and upgraders need heat and hydrogen ^[14]. The oil sands were 32.7 per cent of all Alberta emissions in 2024 ^[7].
• Conventional decline. Natural gas production and processing fell by about a third after 2005, and conventional oil fell by about a third after 2014 (calculated from the inventory) ^[2]. Nationally, ECCC reports that emissions from conventional oil and gas fell by about 43 Mt between 2005 and 2024, offsetting most of a 59 Mt rise from the oil sands, and it credits federal and provincial methane measures for a 34 per cent drop in fugitive emissions ^[1][15].
• Refining is small. Refining emitted 5.1 Mt in 2024, far less than upgrading ^[2]; see Upgrading and refining in Alberta.

A note on comparing numbers: our oil sands guide cites about 92 Mt for oil sands emissions in 2024. That is the national figure. It includes about 6.6 Mt from thermal heavy oil and upgrading in Saskatchewan, which is why Alberta's own oil sands total is 85.1 Mt (calculated from the inventory) ^[16][15][2].

Grouped by process, Alberta's venting emissions fell from 43.4 Mt in 2014 to 27.8 Mt in 2024, while flaring rose from 3.2 Mt to 5.0 Mt ^[17]. The methane sections below explain why.

Emissions intensity versus absolute emissions

Emissions intensity is emissions per unit of product, such as kilograms of CO₂e per barrel. Absolute emissions are the total tonnes released. The two can move in opposite directions.

The Government of Alberta reports that the emissions intensity of oil sands bitumen production fell 28 per cent per barrel from 2012 to 2024, while production grew 105 per cent. In situ intensity fell 14.3 per cent, from 0.489 to 0.419 tonnes of CO₂e per cubic metre, and integrated mining intensity fell 26.3 per cent, from 0.587 to 0.432 tonnes per cubic metre ^[7].

S&P Global estimates average oil sands intensity fell 2 per cent in 2025 to 59 kg CO₂e per barrel, the 13th straight annual decline and about 31 per cent below 2009. It credits efficiency gains at mines, Quest carbon capture (2015), Suncor's coke boiler replacement (2024) and the growing share of steam-assisted gravity drainage (SAGD) and mined bitumen shipped without upgrading, both less intensive on average than integrated mines with upgraders ^[3].

Yet absolute oil sands emissions kept rising. S&P estimates they rose 2 per cent from 2024 to 2025 as output grew by 150,000 barrels per day ^[3]. In the inventory, Alberta's oil sands emissions went from 54.4 Mt in 2012 to 85.1 Mt in 2024 (calculated from the inventory) ^[2]. Put simply, doubling production while cutting intensity by about a quarter still adds up to roughly half again as much total emissions (calculated).

Three cautions apply to intensity figures:

• They are production-stage numbers. They leave out emissions from burning the fuel.
• Definitions differ. Some series measure per barrel of bitumen, others per barrel of marketable product, so figures are not always comparable ^[7][3].
• Measurements can disagree with reports. A 2019 aircraft study led by John Liggio found oil sands CO₂ intensities 13 to 123 per cent higher than estimates from public data, and total oil sands emissions about 30 per cent (17 Mt) higher than industry reported for 2013 ^[18]. A 2023 reply by an Alberta government scientist and a co-author argued the gaps could be explained by uncertainty and bias in the study's methods ^[19].

Methane: sources and the numbers

Methane (CH₄) is the main component of natural gas. Alberta describes it as trapping heat 28 times more effectively than CO₂, the 100-year figure both the provincial and national inventories use ^[4][2]. It stays in the air for a shorter time, so its effect over shorter periods is larger still; news coverage often cites more than 80 times ^[20]. Cutting methane therefore slows warming faster ^[4].

Where oil and gas methane comes from

• Venting: deliberate release of gas without burning it, for example gas that comes up with oil or is released during equipment maintenance ^[4].
• Pneumatic devices: valves, controllers and small pumps driven by pressurized natural gas that is then released. In 2024 they made up about half of the source-specific emissions reported to the AER, and gas batteries accounted for about 76 per cent of pneumatic emissions ^[5].
• Fugitive emissions: unintended leaks from valves, flanges, seals and other components ^[4].
• Flaring: burning unwanted gas. Flaring turns most methane into CO₂, which is less harmful, but some methane passes through unburned ("methane slip") ^[4].
• Compressor seals and glycol dehydrators: equipment-specific sources with their own limits ^[21].
• Surface casing vent flow and gas migration: gas leaking up around a well's casing. At the end of 2024, 11,038 wells had unresolved events, releasing an estimated 97.0 million m³ of gas a year ^[5].

Much of the gas is solution gas, produced along with crude oil and bitumen ^[22]. Operators can conserve it (sell or use it), flare it or vent it.

What the regulator's data show

The AER's annual ST60B report compiles volumes operators report through Petrinex, the provincial production reporting system, and the AER's OneStop platform ^[23][5]. The December 2025 edition covers 2024:

• Fuel gas burned on site rose 7.7 per cent to 29.5 billion m³ ^[5].
• Flaring rose 11.9 per cent to 1,534.1 million m³, and solution gas flaring rose 19.3 per cent to 914.5 million m³ ^[5].
• Venting fell 9.7 per cent to 273.9 million m³ ^[5].
• Solution gas conservation slipped from 97.25 per cent to 96.51 per cent ^[24].
• Equipment fugitives rose about 15 per cent to 40.4 million m³ ^[5].

Source: AER ST60B-2025. Definitions changed in 2020, so earlier years are not comparable ^[5].

The AER attributes the flaring increase to higher oil and bitumen output, the 2020 definition changes and new methane limits. Operators can cut venting either by conserving gas or by burning it, and many chose combustion, which raises reported flaring ^[5]. The report excludes oil sands mining schemes and some oil sands processing plants ^[5].

Methane rules and targets

Alberta's rules and the 45 per cent goal

In 2015, Alberta committed to cut oil and gas methane 45 per cent below 2014 levels by 2025, describing itself as the first regional government in North America to set such a target ^[7]. The AER turned the goal into requirements in two directives, backed by the provincial Methane Emission Reduction Regulation ^[4]:

• Directive 060 sets rules for flaring, incinerating and venting at upstream wells and facilities, including in situ oil sands operations but not oil sands mines. The current edition took effect March 27, 2026 ^[25].
• Directive 017 sets what gas volumes must be measured, how they may be estimated and what must be reported ^[26].

Key Directive 060 limits, as summarized by the AER in April 2025, include ^[21]:

• An overall site vent limit of 15,000 m³ of gas a month (or 9 tonnes of methane).
• A limit below 3,000 m³ a month of routine "defined vent gas" at sites built from 2022, with a fleet-average option for heavy oil (crude bitumen) batteries.
• New pneumatic devices must prevent or control venting, and older instruments must vent less than 0.17 m³ an hour.
• Leak surveys three times a year at many gas plants and compressor stations, once a year at batteries, and annual screening at well sites.

The AER's estimates show the steady decline:

Source: AER analysis on Alberta's methane page, excluding oil sands mining, tailings and upgrading, at a warming factor of 28. Percentages calculated ^[4].

The province reached 45 per cent in 2022, three years early, and 51 per cent by 2024 ^[27][5]. The figures combine reported data with estimates for sources that have no reporting requirement, and the AER updates the model each year, so the baseline can shift ^[5]. Oil sands mining and upgrading methane, mostly from mine faces and tailings ponds, is regulated through the TIER carbon pricing system instead ^[4]. Alberta also used offsets: pneumatic device conversions had generated about 6.3 million active credits by April 2026 ^[7].

Federal methane rules

Ottawa's first methane regulations, finalized in April 2018, targeted a 40 to 45 per cent cut in oil and gas methane below 2012 levels by 2025. Canada later set a goal of at least 75 per cent below 2012 by 2030 and published draft amendments in December 2023 ^[28]. National oil and gas methane in the inventory was about 44 per cent below 2012 in 2024 (calculated from the inventory) ^[2].

The final amendments were announced on December 16, 2025, and published in the Canada Gazette on December 31, 2025 ^[29][30]. They:

• prohibit routine venting of hydrocarbon gas at upstream facilities, with limited exceptions;
• require regular leak inspections with repair deadlines;
• require flares and other gas destruction equipment to reach at least 98 per cent carbon conversion efficiency;
• offer an alternative, measurement-based path for facilities that keep methane intensity below set thresholds ^[30].

Most requirements start January 1, 2028, with further venting and destruction rules in 2030. ECCC estimates 304 Mt of cumulative reductions from 2028 to 2040, costs of $14.6 billion and benefits of $38.6 billion ^[30].

The 2035 equivalency deal

Federal rules do not apply where a province has an "equivalency agreement" showing its own rules achieve the same result. Alberta, British Columbia and Saskatchewan have had such agreements since 2020 ^[29]. The November 27, 2025 Canada-Alberta memorandum of understanding (MOU) set a new target for Alberta: 75 per cent below 2014 levels by 2035, rather than 2030 ^[9][20].

An agreement in principle published March 25, 2026, commits both governments to release a draft for 60 days of public comment, finalize it by the end of 2026 and bring it into force by January 1, 2027, for 10 years. An independent third party, jointly chosen and paid for, will model and assess results, and Alberta commits to corrective action if emissions are higher than expected ^[31]. Alberta plans to reach the target with regulations, offset credits and investments ^[31]. This guide could not confirm whether the draft agreement had been published by late September 2026.

Measuring methane: why the numbers differ

Methane is invisible and releases are often intermittent, so counting it is hard. There are two broad approaches:

• Bottom-up estimates add up individual sources using equipment counts, engineering calculations, emission factors and site surveys.
• Top-down estimates measure methane in the air from aircraft, satellites, vehicles or towers and work back to the sources ^[4].

The Alberta government says its system uses both, including aerial surveys commissioned by the AER, vehicle-mounted sensors and more than 1,500 AER compliance activities in 2023 ^[4].

The two approaches often disagree. A 2023 peer-reviewed study by Bradley Conrad and colleagues combined aircraft and ground measurements to build a methane inventory for Alberta's conventional upstream operations. It put 2021 emissions at 1,337 kilotonnes, about 1.5 times the official federal inventory, and found venting from sources such as uncontrolled tanks, pneumatics and unlit flares made up almost two-thirds of the total ^[32]. Its estimates matched independent aerial and satellite measurements within uncertainty ^[32].

Official estimates also differ from each other. The AER's figure for 2024 is 14.8 Mt CO₂e ^[4]. The national inventory, for roughly the same sources (gas production and processing, conventional oil and in situ oil sands), shows about 28 Mt in 2024 and a decline of about 44 per cent from 2014 (calculated by this guide from the inventory file; the scopes are close but not identical) ^[2]. Both show large reductions. They differ on the starting level and the size of the cut, which is one reason the 2026 agreement in principle calls for independent third-party analysis ^[31].

Carbon pricing and the emissions cap

How TIER works

Alberta has priced large industrial emissions since 2007 ^[6]; the Pembina Institute calls it the longest-running industrial carbon pricing system in North America ^[33]. Today's version is the Technology Innovation and Emissions Reduction (TIER) Regulation. It covers facilities that emitted 100,000 tonnes of CO₂e or more in 2016 or any later year, and smaller trade-exposed facilities can opt in ^[34]. In 2024 it covered 164.7 Mt, or 63.3 per cent of provincial emissions ^[7].

Each facility gets a benchmark, an allowed emissions intensity per unit of output. A facility that emits more than its benchmark must cover the gap by ^[34]:

• reducing emissions on site, including through captured and stored CO₂;
• submitting emission offset credits, earned by verified reduction projects outside TIER, such as wind power or pneumatic device conversions;
• submitting emission performance credits, earned by facilities that beat their own benchmarks;
• paying into the TIER Fund at the set "fund price" per tonne.

Because the fund price is the most anyone has to pay, it acts as the headline carbon price; traded credits can sell for less ^[8]. Between 2007 and 2024, facilities paid $5.005 billion into the fund, and Alberta has invested $2.8 billion of fund money in technology since 2009 ^[7]. In December 2025, Alberta amended TIER to let facilities count direct on-site investments in emission-reduction projects toward compliance and to let some smaller facilities opt out for 2025 ^[34].

The freeze and the federal benchmark

Canada sets a national minimum standard, or benchmark, for carbon pricing; provinces whose systems meet it avoid the federal backstop. The federal fuel charge on consumers ended April 1, 2025 ^[34].

On May 12, 2025, Premier Danielle Smith froze the TIER price at $95 a tonne "indefinitely," citing U.S. tariffs and competitiveness. It had been scheduled to rise to $110 in 2026 and $170 by 2030 ^[6]. In September 2025, Alberta said the price would stay at $95 through 2026, which the Pembina Institute said put TIER out of step with the federal benchmark ^[33].

The 2025–2026 carbon pricing deal

The November 2025 MOU committed both governments to a TIER system that ramps up to a "minimum effective credit price" of $130 a tonne ^[9]. The May 15, 2026 Implementation Agreement filled in the details ^[8][35]:

Sources: CBC News, Prime Minister's Office and ClearBlue Markets ^[6][8][35].

The deal also includes 75 Mt of carbon contracts for difference, with costs shared equally, which the governments say will make carbon prices predictable for emission-reduction projects. The federal release was blunt about the existing market: "Canada's carbon credit markets are not working," citing an oversupply of low-priced credits ^[8]. Canada said it would align its updated federal benchmark with the new framework ^[35].

The federal emissions cap

In November 2024, Ottawa published draft regulations for a cap-and-trade system covering upstream oil and gas, including oil sands, upgrading and gas processing, plus liquefied natural gas (LNG). For 2030 to 2032, the cap would have been 27 per cent below 2026 reported emissions, estimated to equal about 35 per cent below 2019, with offsets and other flexibility allowed for up to 20 per cent of obligations ^[36].

In March 2025, the Parliamentary Budget Officer estimated that meeting the cap's legal upper bound of 160 Mt would require upstream production 4.9 per cent below projected levels in 2030 to 2032, lowering real GDP by 0.39 per cent in 2032 ^[37]. The PBO's analysis excluded the benefits of lower emissions ^[37].

The final regulations were never implemented. Budget 2025, tabled November 4, 2025, set conditions under which the cap would no longer be needed: effective carbon pricing, stronger methane rules and carbon capture at scale ^[38]. In the November 27, 2025 MOU, Canada agreed it "will not implement" the cap ^[9]. As of September 2026 the cap is shelved: it was never law, and no regulations are in force.

Carbon capture and storage

Carbon capture and storage (CCS) separates CO₂ from an industrial exhaust or process stream, compresses it into a dense, liquid-like state, pipes it away and injects it deep underground for permanent storage ^[14]. When captured CO₂ is injected into oil fields to push out more oil, it is called enhanced oil recovery (EOR), and Alberta's offset system credits the CO₂ stored this way ^[7]. Together these are often called CCUS, adding "utilization."

Alberta has decades of related experience, from solvent injection in oil fields in the late 1950s to disposal of acid gas at sour gas plants. It passed Canada's first comprehensive carbon sequestration law in 2010 ^[10].

Alberta's operating and planned projects

Sources: Government of Alberta, International CCS Knowledge Centre, World Oil and the trilateral MOU ^{[10][14][39][40]}.

Quest

Quest, operated by Shell and owned mainly by Canadian Natural, captures CO₂ from the three hydrogen manufacturing units at the Scotford Upgrader, which make hydrogen needed to upgrade bitumen ^[10][14]. Almost all industrial hydrogen is made from natural gas by steam methane reforming, which releases CO₂ ^[41]. The CO₂ travels 65 km by pipeline and is injected about 2 km down into the Basal Cambrian Sands ^[10][14]. It is designed to capture about 35 per cent of the upgrader's CO₂ ^[10]. Alberta committed $745 million and Canada $120 million ^[14].

After a partial first year, injections have run between 0.94 and 1.14 Mt a year, about 9.8 Mt in total to 2024 (calculated from reported annual amounts). Alberta now reports more than 10 Mt stored ^[10].

The Alberta Carbon Trunk Line

The ACTL, which began commercial operations in 2020, is a 240 km pipeline carrying CO₂ from the Sturgeon Refinery and the Nutrien Redwater fertilizer plant to EOR projects in central Alberta. Its design capacity of 14.6 Mt a year leaves room for future sources. Reported injections totalled about 6.1 Mt to 2024 (calculated); operator Enhance Energy reports more than 8 Mt since start-up. Alberta committed $495 million ^[10]. The province says Quest and the ACTL together have stored more than 17 Mt since 2015 ^[10].

Pore space, hubs and federal support

In Alberta, the Crown owns the deep "pore space" in rock where CO₂ is stored. Under the Mines and Minerals Act, the province can grant rights to use it, and the Act sets a framework for transferring long-term liability ^[42]. The AER approves injection schemes and has overseen monitoring, measurement and verification plans and closure plans since April 25, 2023 ^[43][42].

To avoid a patchwork of overlapping projects, Alberta allocates storage through competitive "hub" rounds. Six proposals were selected in the Industrial Heartland near Edmonton and 18 more across the province, including one by the Pathways Alliance. Winners first sign evaluation agreements, then apply for a carbon sequestration agreement that requires open access at affordable rates where appropriate ^[43]. In October 2025, Alberta opened a new call for the northwest after earlier proponents there stepped away from their plans ^[44].

Ottawa supports CCS with an investment tax credit (ITC): 60 per cent of eligible capture costs for direct air capture, 50 per cent for other capture equipment and 37.5 per cent for transport, storage and use equipment. Budget 2025 extended these full rates to spending through the end of 2035, with lower rates from 2036 to 2040. EOR is not eligible ^[45][46]. The November 2025 MOU commits Canada to extend ITCs and other supports to Pathways and EOR ^[9]. Alberta's own Carbon Capture Incentive Program offers a 12 per cent grant on eligible capital costs ^[10].

The Pathways project and the 2026 agreements

The Pathways Alliance brought together five of Canada's largest oil sands producers: Canadian Natural, Cenovus, ConocoPhillips, Imperial and Suncor. On February 20, 2026, the group renamed itself the Oil Sands Alliance, keeping "Pathways" as the name of its proposed CO₂ pipeline and storage hub ^[47]. The province lists the alliance as committed to carbon neutrality by 2050 ^[10].

The Pathways Project would link capture plants at oil sands sites to a main pipeline running between the Fort McMurray and Cold Lake regions, with connecting lines forming a network of more than 650 km. The CO₂ would be stored deep in the Basal Cambrian formation at a hub in the Cold Lake area ^[48][11]. Canadian Natural began filing regulatory applications in early 2024; pipeline right-of-way filings are substantively complete, while storage-hub applications are still being prepared ^[48]. Cost estimates have risen from about $16.5 billion in 2023 to more than $20 billion in 2026, according to news reports ^[49][50].

The trilateral MOU

The November 2025 MOU made Pathways and a proposed new bitumen pipeline to the West Coast "mutually dependent": each is a precondition for the other ^[9]. In July 2026, Canada, Alberta and the Oil Sands Alliance companies signed a non-binding trilateral MOU ^[40][11]:

• Phase 1: Pathways CCS capturing about 6 Mt of CO₂ a year, with shared infrastructure in service by January 1, 2032, and completion by January 1, 2035 ^[40].
• Phases 2 and 3: a further 5 Mt a year by 2040 and another 5 Mt by 2045, from more CCS or other technologies, for a total of 16 Mt a year (net) ^[40].
• Carbon pricing: participating companies that deliver their reductions face a 1 per cent annual tightening of TIER benchmarks instead of 2 per cent; companies that fall short face tougher benchmarks ^[40].
• Support: Alberta extends its carbon capture incentive program to 2035 and Canada offers advance financing for CCS operating costs ^[40].
• Next step: binding "definitive agreements" with each company, targeted by November 15, 2026 ^[40].

The alliance says the project remains subject to those agreements and to regulatory approval ^[11]. In May 2026, Canada's National Observer reported that the 16 Mt goal was a quarter below an earlier pledge of 22 Mt a year by 2030 ^[50]; the July memorandum spreads the 16 Mt over phases ending in 2045 ^[40].

Other ways to cut emissions

Cogeneration

Cogeneration produces electricity and useful heat (such as steam) from the same fuel. The Canada Energy Regulator (CER) notes it can reach up to 92 per cent efficiency, compared with about 57 per cent for a combined-cycle power plant. In 2015, Alberta had 4,528 megawatts (MW) of industrial cogeneration capacity at 32 facilities, of which 3,343 MW served the oil sands, and surplus power is sold to the grid ^[51].

Solvents in place of steam

Because steam generation drives in situ emissions, producers are testing ways to use less steam ^[13]. Imperial's Grand Rapids project at Cold Lake began production in May 2024 as the first commercial use of solvent-assisted SAGD, which mixes a lighter hydrocarbon with the steam. Imperial expects it to cut emissions intensity by up to 40 per cent compared with existing processes, with an initial target of 15,000 barrels per day ^[13]. See our oil sands guide for other in situ methods.

Electrification and the grid

Replacing gas-fired engines, compressors and heaters with electric ones only helps if the power is low-emitting. Alberta's grid intensity fell from 907 grams of CO₂e per kilowatt-hour in 2005 to 335 grams in 2024, after coal power ended ^[7]. The 2025 MOU calls for large transmission links to British Columbia and Saskatchewan to supply lower-carbon power to oil, LNG and carbon capture operations, and for a net-zero grid by 2050 ^[9]. The May 2026 agreement adds a goal of roughly doubling Alberta's grid by 2050 ^[8].

Small modular reactors

Small modular reactors (SMRs) could in theory supply the steam and power oil sands sites now get from natural gas. Emissions Reduction Alberta estimates a first 400-megawatt (thermal) unit could avoid about 560,000 tonnes a year. But Cenovus ended its funded engineering study in 2024 after early work found long, uncertain timelines, high capital costs, immature supply chains and gaps in Alberta's regulatory framework; reactors hot enough for SAGD would also be advanced designs with little commercial experience ^[52]. Under the 2025 MOU, Alberta is to develop a nuclear generation strategy by January 1, 2027 ^[9].

Hydrogen

Hydrogen is already essential to upgrading ^[14]. Air Products runs three hydrogen plants and a 55 km hydrogen pipeline network in Alberta's Industrial Heartland ^[53]. It is building a "net-zero" hydrogen complex in Edmonton that will use autothermal reforming, designed to capture more than 90 per cent of process CO₂, plus a hydrogen-fuelled power unit and a liquid hydrogen plant ^[41]. The project has faced delays and cost increases that the company's chief executive called "unforgivable" in May 2025 ^[54]. In April 2026, Air Products said construction was "well underway" ^[53].

Air quality and legacy issues

Other air pollutants

Oil and gas also releases local air pollutants. In 2024, the oil and gas industry was Canada's largest source of nitrogen oxides (NOₓ), at 37 per cent of national emissions, and of volatile organic compounds (VOCs), at 40 per cent. It also produced about 42 per cent of sulphur oxides (SOₓ) ^[55].

Measurement questions arise here too. A 2024 study in Science by ECCC and Yale University researchers used 30 flights over 17 oil sands facilities in 2018 and found total organic carbon emissions 20 to 64 times higher than industry reported, depending on the facility. The Pathways Alliance said the difference between aircraft and ground measurements warranted further review ^[49].

The Oil Sands Monitoring Program is a joint Alberta-Canada program, with Indigenous and industry participation, that studies the long-term cumulative environmental effects of oil sands development ^[56]. Industry pays for it under a formula set in 2013 of up to $50 million a year. For 2025, the budget was $54.5 million against about $76 million of requested work, and Indigenous representatives warned that inflation had eroded its purchasing power ^[57].

Flaring history

Flaring was once far more common. Following recommendations from the Clean Air Strategic Alliance (CASA), a multi-stakeholder group of industry, government and environmental organizations, the regulator set the flaring and venting requirements that became Directive 060 ^[22][5]. By 2006, solution gas flaring was 71.5 per cent below 1996 levels, venting was 56.4 per cent below 2000, and industry conserved 96.03 per cent of solution gas ^[22]. Conservation was 96.51 per cent in 2024, similar to 2006, even as flaring volumes climbed after 2020 ^[24].

In December 2025, Reuters and CBC News reported, based on access-to-information records, that the AER had quietly dropped a 20-year-old provincial flaring limit by June 2025, after companies exceeded it in consecutive years and government officials urged a "softer" approach. The report said 2024 flaring exceeded the annual provincial limit by 36 per cent. The AER said it had not enforced the limit because the policy was under review, and that it had disclosed the change in a regulatory filing on its website ^[58]. Canada has endorsed the World Bank goal of ending routine flaring by 2030 ^[58].

Orphan and inactive wells

Wells and facilities left behind by defunct companies become "orphans" and are closed by the industry-funded Orphan Well Association (OWA). Old or poorly sealed wells can leak methane: in 2025 the OWA resealed a well drilled in 1954 that had leaked natural gas into a home in Bonnyville ^[59]. Since 2002 the OWA has decommissioned more than 8,900 wells and received more than 4,100 reclamation certificates. In 2025–26, its well inventory grew 13 per cent, industry levy funding rose to $141.3 million and it received 850 reclamation certificates, its highest annual total ^[59].

For oil sands mine reclamation and tailings, see our oil sands guide.

Contested questions

Is intensity progress enough?

• Industry and the province: Oil sands intensity has fallen for 13 straight years ^[3]. Alberta's total emissions fell 9.8 per cent from 2015 to 2024 while its economy grew ^[7]. S&P's Kevin Birn calls the decline "a well-established, multi-decade trend" ^[3].
• Critics: Absolute oil sands emissions keep rising ^[3]. The Pembina Institute says oil sands emissions have risen about 150 per cent since 2005 and are undercutting cuts made elsewhere in the economy ^[33]. S&P itself expects absolute emissions to keep growing with production unless carbon capture is applied ^[3].

Are the reported numbers accurate?

• Critics: Independent measurements have repeatedly found more methane, CO₂ and organic pollutants than reported ^[32][18][49].
• Defenders: Alberta says its combined top-down and bottom-up system is robust, and an Alberta government scientist has argued that the gaps found in one aircraft study could be explained by uncertainty and bias in its methods ^[4][19]. Industry says it follows ECCC methods and will look at improving measurement ^[49].

Is carbon pricing strong enough, or too strong?

• Industry: The Canadian Association of Petroleum Producers backed the 2025 freeze and called for a reset of federal climate rules, saying changes were needed to keep investment competitive ^[6].
• Critics: Pembina argues the freeze and new compliance options weaken the credit market, making investments such as carbon capture less likely ^[33]. Even the federal government said in 2026 that the credit market was "not working" ^[8].

Was dropping the emissions cap right?

• For dropping it: The PBO estimated the cap would cut projected production and GDP, and the Pathways Alliance said the report confirmed that "an emissions cap is a production cap" ^[37][60]. Ottawa's budget argued that carbon pricing, methane rules and CCS would make it unnecessary ^[38].
• Against: Critics say the replacement measures are weaker or slower. The Pembina Institute said moving Alberta's methane deadline to 2035 would undercut the federal rules, and the Canadian Climate Institute has said policy rollbacks mean Canada will miss its 2030 target ^[20].

Can carbon capture deliver?

• Supporters: Quest and the ACTL have operated for years and stored more than 17 Mt combined ^[10]. The federal government says Pathways and related measures would deliver 16 Mt a year of reductions ^[8].
• Skeptics: A 2022 analysis by the campaign group Global Witness said Quest captured only 48 per cent of the plant's carbon emissions; Shell called that "simply wrong," noting Quest was designed to capture about a third of the CO₂ ^[61]. Critics also note Pathways' targets have been scaled back and delayed and that its cost has risen past $20 billion ^[50].

What is not in dispute: methane from conventional oil and gas has fallen sharply, oil sands emissions have risen, and the largest planned capture project, Pathways, still awaits binding agreements and regulatory approval ^[11].

FAQ

How much greenhouse gas does Alberta's oil and gas industry emit? About 153.6 Mt of CO₂e in 2024, roughly 59 per cent of Alberta's total of 260.1 Mt (calculated from the inventory) ^[2]. Nationally, the oil and gas sector emitted 208 Mt, about 30 per cent of Canada's total ^[1].

Did Alberta meet its methane target? Yes, by the province's measure. The AER estimates upstream methane was 45 per cent below 2014 in 2022, three years early, and 51 per cent below by 2024 ^[4][5]. The national inventory shows a smaller cut from a higher starting level for similar sources, and independent studies suggest actual emissions may be higher than reported ^[2][32].

Why is flaring going up if methane is going down? Alberta's rules push operators to stop venting methane. Burning gas instead of venting it cuts its warming effect ^[58], so many operators chose to flare, and oil and bitumen production also grew. Reported flaring rose 11.9 per cent in 2024 to 1,534.1 million m³ ^[5].

What is Alberta's carbon price in 2026? The TIER fund price is $95 a tonne, frozen since May 2025 ^[6][7]. Under the May 2026 federal-provincial agreement, it rises to $115 by 2030 and $130 by 2035, with a price floor for traded credits from 2030 ^[8][35].

Is there a cap on oil and gas emissions in Canada? No. The federal cap was published only in draft in 2024, and in November 2025 Ottawa agreed not to implement it ^[36][9].

How much CO₂ has Alberta stored underground? The province reports more than 17 Mt stored by Quest and the Alberta Carbon Trunk Line since 2015 ^[10]. That is roughly what Canada's oil and gas sector emits in one month (calculated from the 2024 inventory) ^[1].

Will the Pathways project be built? It is not yet certain. A July 2026 memorandum targets the first phase in service by 2032, but binding agreements and regulatory approvals are still pending, and the project is formally linked to a proposed West Coast bitumen pipeline ^[40][11][9].