According to the Fourth Biennial Update Report to the UNFCCC in 2021, there were 58 projects registered with carbon markets, 46 of them under the Clean Development Mechanism (CDM). However, there were no new projects under CDM between 2016 and the publication of the 2021 report, while projects registering in voluntary markets had increased. Most of the energy projects centered on wind, solar, hydro, and biomass power generation; several captured and used methane emissions from the waste sector. YPF has two projects registered under the CDM, intended to reduce emissions in the La Plata and Luján de Cuyo industrial complexes. Combined, the two projects avoided about 168,687 tCO2 emissions in 2019. YPF also engages in carbon offset programs, such as reforestation in the Neuquén province. Started in 1998, these efforts sequestered an estimated 760,000 tCO2e over the course of 30 years.

The Carbon Credits (Carbon Farming Initiative) Act, 2011, made GHG emissions reduction possible for crediting companies across the economy. The Carbon Farming Initiative Amendment Act, 2014, established the Emissions Reduction Fund, which is administered by CER and is now known as the Australian Carbon Credit Unit (ACCU) Scheme. Companies can earn ACCUs for reducing fugitive leak and venting emissions at oil and gas extraction, production, transport, and processing facilities by installing and operating equipment to capture these gases and combusting them in a flare device. The Carbon Credits (Carbon Farming Initiative—Oil and Gas Fugitives) Methodology Determination, 2015, establishes “procedures for estimating abatement (emissions reduction and sequestration) from eligible projects, and rules for monitoring, record keeping and reporting.”

Alberta put a price on carbon emissions for large industrial emitters in 2007. It put a carbon levy on fuel from 2017 until its repeal in 2019. In December 2019, Alberta passed Bill 19, the Technology Innovation and Emissions Reduction Implementation Act, which laid the foundation of the market-based Technology Innovation and Emissions Reduction (TIER) system to induce industries to reduce emissions. Facilities that voluntarily reduce emissions may qualify for offsets or performance credits under the Alberta Emission Offset System. In 2019, the original TIER Regulation  set a price of Can$30 (about US$24 as of September 2021) per tCO2e on emissions from the oil and gas, electricity, cement, agriculture, and other sectors. The benchmark price rises to Can$40 (about US$32 as of September 2021) per tCO2e in 2021 and Can$50 (about US$39 as of September 2021) per tCO2e in 2022. This regulation meets the federal criteria. In the past, the carbon price applied to facilities that had emitted 100,000 tCO2e or more a year in 2016 or subsequent years. An amendment in July 2020 allowed facilities that emit between 10,000 and 100,000 tCO2e to voluntarily comply with the regulation, or opt in, and reduce the administrative burden for regulated conventional oil and gas facilities in exchange for an exemption from Canada’s federal carbon price (see section 22 in the preceding case study).  Also, firms are offering a lease-to-own program for nonemitting facility equipment. This program allows companies to voluntarily reduce emissions and generate carbon credits to pay down equipment leases. To align with the federal changes discussed in section 22 of the preceding case study, the TIER Regulation was updated at the end of 2022 . Carbon prices will match federal prices set for the 2023–30 period. The opt-in threshold is lowered from 10,000 to 2,000 tCO2e per year, enabling smaller firms to participate in the offset market. Amended regulations introduce two new credit classes: sequestration credits and capture recognition tonnes. Companies can convert the emissions offsets associated with a sequestration project to sequestration credits, which follow the same rules governing banking, trading, and compliance. Companies can convert sequestration credits to capture recognition tonnes, which must be used in the year of capture. Amended regulations increased credit use limits (“true-up obligation”—the quantity by which a regulated facility’s total regulated emissions exceed its permissible emissions for the year) to 90 percent by 2026. Since offsets and credits can be used only once by their owner, the higher percentage is expected to encourage the earlier retirement of more offsets and credits and, thus, investment in new emission reduction activities. Also, the TIER system now includes emissions from flaring. The flaring reduction target is set at 10 percent for 2023, with further reductions of 2 percent annually. Venting and fugitive emissions are not considered.

British Columbia implemented the Carbon Tax Regulation, 2008, which was last amended in November 2022. The tax applies to the purchase and use of fossil fuels burned for transport, home heating, and electricity. It covers approximately 70 percent of provincial GHG emissions. The impact of the tax on consumers is compensated for by a reduction in personal and corporate income taxes by an approximately equal amount. The carbon tax increased gradually from Can$10 (about US$7.9 as of September 2021) per tCO2e in 2008 to Can$30 (about US$24 as of September 2021) per tCO2e in 2012, at which point the government froze the rate at Can$30 per tCO2e until other jurisdictions implemented similar carbon taxes. In 2018, the carbon tax was increased to Can$35 (about US$28) per tCO2e; in April 2019, it rose to Can$40 (about US$32 as of September 2021) per tCO2e, which for natural gas corresponds to Can$0.076 per m³. The updated regulation sets Can$50 per tCO2e for 2022 and beyond. The carbon taxes by fuel type are updated through 2026. The Ministry of Environment and Climate Change Strategy has been managing a carbon offset program since 2010. In the oil and gas sector, offset projects have reduced flaring or venting, typically by using gas for electricity generation.

In October 2016, the federal government published the Pan-Canadian Approach to Pricing Carbon Pollution, which established the federal benchmark for the 2018–22 period. In December 2016, Canada’s First Ministers adopted the Pan-Canadian Framework on Clean Growth and Climate Change , which required all provinces and territories to implement carbon pollution pricing systems by 2019. Under the federal legislation, the Greenhouse Gas Pollution Pricing Act, 2018, the federal government introduced a two-part carbon pricing scheme: a fuel charge and an output-based pricing system (OBPS). The fuel charge started with a carbon price of Can$10 (about US$7.9 as of September 2021) per tCO2e, increasing to Can$30 (about US$24 as of September 2021) in 2021 and Can$50 (about US$39 as of September 2021) by 2022. The federal benchmark is updated to have an initial carbon price of Can$65 (about US$47.8 as of May 2023) in 2023, and this price is to increase by Can$15 (about US$11) every year to reach Can$170 (about US$125) in 2030 . This price applies in all provinces that do not set their own prices. The OBPS must be designed to encourage facilities to reduce their emissions. Performance standards must be set such that, at a minimum, the marginal price signal is equivalent to the federal benchmark. Provinces can set their emissions intensity standards. Facilities able to reduce their emissions below these standards are eligible for performance credits. The OBPS “must only apply to sectors that are assessed by the jurisdiction as being at risk of carbon leakage and competitiveness impacts from carbon pollution pricing.” The federal carbon pricing regime does not cover all industries. Methane emissions from the oil and gas value chain, for example, are not comprehensively addressed. Some provinces adopted the federal carbon pricing benchmark or introduced their own carbon tax, while others combined provincial fuel charges with the federal OBPS or vice versa. In all cases, provincial measures must be equivalent to the federal benchmark. Quebec and Nova Scotia have cap-and-trade systems, where the caps must be set consistent with the minimum carbon price. In 2019, Canada began designing the GHG offset program to encourage the cost-effective reduction of domestic GHG emissions or GHG removal projects from activities not covered by carbon pricing. The government issues offset credits only to projects that produce real, quantified, verified, and unique reductions in GHG. This offset program could provide incentives for upstream oil and gas producers to invest in offset projects.

The 2016 Pan-Canadian Framework on Clean Growth and Climate Change  set a federal benchmark, requiring all provinces and territories to implement carbon pollution pricing systems by 2019. Saskatchewan has an output-based pricing system, which is mandatory for facilities emitting more than 25,000 tonnes of CO2e per year and voluntary for facilities emitting more than 10,000 tonnes of CO2e per year. The minimum threshold was removed for upstream oil and gas facilities in late 2020. To comply, companies can pay the Saskatchewan Technology Fund a carbon fee, which was Can$30 (about $22 in May 2023) in 2020.

In May 2017, at the One Planet Summit in Paris, Colombia joined Canada, Chile, Costa Rica, Mexico, and the US states of California and Washington and the Canadian provinces of Alberta, British Columbia, Nova Scotia, Ontario, and Quebec in launching the Carbon Pricing in the Americas Cooperative Framework. Law 1931/2018 established the National Program of Greenhouse Gas Emissions Tradable Quotas, a national emissions trading system (sistema de cupos y créditos), which is still awaiting implementation.

No direct evidence regarding market-based principles could be found in the sources consulted. Carbon dioxide emissions from the oil and gas sector are covered under the EU Emissions Trading System (EU ETS) Act No. 99 Relating to Greenhouse Gas Emission Allowance Trading and the Duty to Surrender Emission Allowances, 2004, which entered into force in 2005.

ESDM 30/2021  calls for contractors to pursue the utilization of flare gas by signing agreements with flare gas buyers, processing business permit holders, or natural gas trading permit holders, which will use flare gas in commercial applications such as power generation fuels (e.g., compressed or liquified natural gas) (Article 2). Contractors must submit an application for flare gas utilization to SKK Migas or BPMA. The application must include documents on the flare gas source and the corresponding contracted volumes, the delivery point, contract duration, flare gas buyer and infrastructure descriptions, and a copy of the price agreement. Based on an evaluation of the bid parameters, SKK Migas or BPMA will make recommendations to the ESDM, which (through DG Migas) will approve or reject the application.

Kazakhstan initiated the first ETS in Asia in 2013. Phase II covered 2014 and 2015. Phase III was delayed until the establishment, in 2018, of an online platform for monitoring, reporting, and verifying GHG emissions. The Environmental Code was periodically updated to include GHG quotas and related obligations and standards to assist with the evolution of the ETS market. Regulations on GHG emissions published in March 2022 provide further details. Only carbon dioxide emissions are included in the ETS market. Operators of oil and gas installations with annual GHG emissions of more than 20,000 tonnes of carbon dioxide equivalent (tCO2e) must obtain quotas. The penalty for noncompliance was waived in 2013 and 2014, and was about 5 monthly standard units or US$37.5/tCO2e in 2022. Operators of installations with emissions of 10,000–20,000 tCO2e a year must report emissions annually, although they are not required to participate in the ETS. The average 2022 price was about US$1.22 per tCO2e. Under the National Allocation Plan 2022–2025, the cap is 163.7 million tCO2e for 2023, 161.2 million tCO2e for 2024, and 158.8 million tCO2e for 2025.