Article 67 of Law No. 19-13, 2019 , requires both participation contracts and PSCs to include a joint marketing clause for natural gas to be exported. Sonatrach may market the gas on behalf of the partners if all parties agree. Article 121 states that serving the national market is a priority. Partners’ share of gas, or a portion of it, is transferred to Sonatrach if ALNAFT—in consultation with Sonatrach and the Electricity and Gas Regulatory Commission (Commission de Régulation de l’Electricité et du Gaz), which is responsible for forecasting demand—decides that these volumes are necessary to serve the national market (Article 123). Article 131 grants open access to the gas transmission pipeline infrastructure. The ARH sets the tariff. Article 146 allows gas prices to be negotiated by the sellers (Sonatrach or its upstream partners) and the buyers for volumes above the national needs, as determined by the Ministry of Energy and Mines. The ARH sets the price of gas sold to power plants and distribution companies. It must cover costs and fiscal and other charges and provide a reasonable rate of return (Article 147). Gas prices in the domestic market are heavily subsidized. Domestic gas demand increased from about 25 bcm in 2010 to about 45 bcm in 2019, driven largely by subsidized pricing. The government has been pursuing a gasification strategy. There are programs to convert light-duty vehicles to liquefied petroleum gas (LPG) and buses and trucks to compressed natural gas (CNG) to reduce the consumption of oil products. Still, most of the demand growth reflects increased power generation and distribution in cities. Phasing out energy subsidies is seen as necessary to avoid a demand-supply imbalance and encourage further development of nonassociated gas fields. All pipelines are developed and operated by Sonatrach under concessions granted by the Ministry of Energy and Mines (Article 127). Sonatrach delivers gas to liquefied natural gas (LNG), petrochemical and fertilizer plants, and refineries. A state-owned company, Sonelgaz, builds and operates distribution networks and serves other gas consumers.

Natural gas provides more than 60 percent of power generation and more than half of the total energy consumed. Law No. 24.076, 1992, known as the Natural Gas Law, established the basis for deregulation of natural gas transport and distribution industries. The Federal Gas Regulatory Authority, created in 1992 by Decree No. 2255/92, oversees the transportation and distribution of natural gas. Natural gas prices are a mix of regulated and market prices. Before the 2015 energy reform, domestic oil and gas prices were significantly lower than those at trade parity, and public services tariffs did not cover operational costs. The domestic supply of oil and gas was insufficient to meet demand. After 2015, domestic oil and gas prices started to align with international levels. Resolution No. 46-E/2017, as amended by Resolutions No. 419/2017 and 12/2018, introduced producer subsidies to attract investments in unconventional natural gas reservoirs in the Neuquén Basin. A minimum price of US$7.50 per million British thermal units (mmBtu) was guaranteed during 2018, decreasing by US$0.50/mmBtu a year to US$6/mmBtu by 2021. On December 31, 2021, the program was to end, at which point prices were expected to match import-parity values. Law No. 26.197, 2006 , vests the federal government with the authority to grant concessions for interprovincial and export transport. Transport concessions located within the territory of only one province and not connected to export facilities were transferred to the provinces. Operators of pipelines and other transport and distribution infrastructure are required to provide open access to third parties if they have available capacity. Third parties have the right to access this transport infrastructure if they comply with the relevant procedures. The growth of natural gas production will require substantial new investment in infrastructure and export routes in the near and medium term as well as cost-effective production and transport systems. The federal government launched a public tender for constructing and operating a new gas pipeline from the Vaca Muerta area in Neuquén to Saliqueló, south of Buenos Aires. Construction is underway.

Generally, laws and regulations governing GHG emissions also apply to midstream and downstream activities. For example, Part 9.11 of Volume II of the OPGGS Act  provides regulations for preventing petroleum’s wastage or its escape from pipelines conveying it to be flared or vented (see section 3 of this case study for other examples). As discussed in section 15 of this case study, the NGER (Measurement) Determination, 2008, establishes calculation methods and prescribes specific methods for various sources of GHG emissions, including those associated with flaring and venting, and fugitive emissions across the oil and gas midstream and downstream activities. Some states have separate laws and regulations for pipelines, storage facilities, processing plants, refining facilities, and distribution networks, but the requirements appear to be mostly consistent with national GHG emission restrictions.

Petrobras was instrumental in creating Brazil’s gas sector, but the company’s control over the industry discouraged new investors from entering the sector and constrained its growth. The New Gas Market is a government program intended to create an open and competitive natural gas market in Brazil. It aims to make the most efficient use of existing infrastructures, attract new investments, and promote competition in the natural gas market. The program has reduced Petrobras’ market power and end-user prices. Petrobras held a monopoly in Brazil’s oil and gas industry until 1995, when Constitutional Amendment No. 9 was approved, making it possible to introduce competition. The Petroleum Law, 1997 , implements the constitutional amendment. In the case of natural gas, however, it did not promote a significant change in the market structure, with Petrobras remaining the dominant player and a monopolist by default. Law 11.909/2009, Gas Law , was adopted to address issues specific to the natural gas industry and attract new investments. It did not achieve the desired objectives. Resolution 16/2019 established guidelines for an energy policy aimed at promoting competition in the natural gas market and reducing the influence of Petrobras over the market. A Term of Commitment of Assignment (Termo de Compromisso de Cessão) was signed between Brazil’s competition authority and Petrobras. It ended the de facto monopoly of Petrobras. Tax amendments were made providing incentives for gas pipeline transport (Ajuste SINIEF nº 03/2018 and Ajuste SINIEF nº 17/2019). One of the objectives of Resolution 16/2019 was to improve the recovery of associated gas in the pre-salt basin. The discovery of pre-salt gas could double the potential of natural gas supply in Brazil in the next 15 years. However, pre-salt gas fields are more than 1,500 meters below sea level and about 300 kilometers from the coast. In addition, the pre-salt gas is rich in carbon dioxide, the release of which would increase GHG emissions substantially. The delivery of associated gas will require significant investments in capture and gas treatment infrastructure and offshore pipelines. 

AER regulations on flaring, venting, and emissions cover pipeline and storage facilities. Most oil and gas produced in Alberta is exported to other provinces or the United States via pipelines. Occasionally, an imbalance between demand and supply, bottlenecks in pipelines, or permitting delays can affect upstream operations. In 2018, for example, western Canadian oil supply outgrew the export pipeline capacity, resulting in record crude price differentials. Alberta’s government mandated a production curtailment effective January 2019, later extended to December 31, 2020. Such a curtailment would likely reduce emissions from associated gas flaring but only temporarily.

Most gas production in British Columbia is exported to other provinces or the United States via pipelines. Gas production increasingly comes from remote unconventional resource basins, such as the Montney and Horn River in the northeast corner of the province, which are far from consuming regions. The coordination of drilling activity with the development of sufficient midstream capacity can avoid bottlenecks in transport capacity and hence reduce flaring. The regulator encourages producers and third parties to pursue such coordination of midstream capacity and new production.

Market diversity and access are crucial considerations for the Canadian oil and gas industry. The Canadian natural gas market has been fully liberalized since gas prices were deregulated in 1985. Most oil and gas producers rely on pipelines and require provincial and federal policies that allow infrastructure to be built to deliver natural gas to new markets. A license from the appropriate provincial regulator must be obtained to construct and operate a pipeline. The CER, as the federal regulator, has jurisdiction if the pipeline crosses provincial or international boundaries. Federally regulated gas pipelines are generally considered to be contract carriers. The CER sets tariffs and the terms and conditions of access through regulation. The CER has the power to ensure that pipeline tolls are just and reasonable. Access to gas transmission is generally by agreement, but the CER has the power to direct a gas pipeline to provide any available capacity to a third party.

Many of the regulations on flaring, venting, and emissions cover pipeline and storage facilities. Most oil production in Saskatchewan is exported to other provinces or the United States via pipelines. The gaps in the synchronization of drilling activity with the development of sufficient gas midstream capacity can create bottlenecks and lead to increased flaring or venting.

The government has been promoting the use of more natural gas within the economy. It has a strategy for increasing the use of compressed natural gas (CNG) vehicles. The government provides financial support for converting older gasoline or diesel vehicles into CNG, selling new CNG vehicles, and expanding the CNG filling station network. EGAS is expanding the distribution network to connect more residential buildings to gas supplies. The government enacted a new Gas Market Law (No. 196) in 2017 and established the Gas Regulatory Authority in 2017. The sector’s restructuring is intended to introduce competition in the gas market via third-party access to the pipeline network. This restructuring aims to give consumers or gas-trading companies the ability to procure gas supplies from producers within Egypt or via LNG imports. Previously, EGAS was the single buyer of natural gas and the de facto regulator of the gas sector. The Cabinet sets the prices of natural gas delivered to different customer classes. As part of gas market reforms, prices were raised for all buyers except residential consumers. Industries such as cement found the reformed gas prices too high and switched to coal. In 2020, the Cabinet lowered gas prices for all industrial users. Given the increased availability of LNG and increased domestic gas production, lower prices may still allow suppliers to recover costs. The market reforms are promising, since gas prices below cost-recovery levels are among the factors discouraging investment in efforts to reduce flaring and venting at oil and gas facilities. However, the Cabinet’s differentiation of prices by customer class, and the risk of frequent readjustments, create uncertainty. These reforms and government efforts to increase gas use may create incentives for operators to capture more of the associated gas they are currently flaring or venting. The strength of the incentive depends on the proximity of the field to processing facilities and pipeline networks, the age of the field, the gas-to-oil ratio, the share of natural gas liquids in produced volumes, and other technical and geological factors. The recovery and utilization of flared associated gas is listed as a mitigation action in Egypt’s updated NDC of June 2022. The NDC mentions 17 implemented projects and another 36 projects to be implemented by 2030. Projects typically use captured gas for on-site power generation to replace diesel, or access existing pipelines and processing facilities

Article 1 of the 2021 proposal  defines the regulation’s scope by including all key elements of upstream and midstream operations, most notably oil and fossil gas upstream exploration and production, gas gathering and processing, transmission, distribution, underground storage, and LNG terminals. Downstream operations are subject to Directive 2010/75/EU, 2010, which is under revision.