Country
Assessment
Several regulations relate to the transport and pricing of gas that is sold to other sectors further downstream (see section 3 of this case study). Downstream activities are supervised by a separate regulatory agency, BPH Migas. Article 31 of Government Regulation 36/2004 requires midstream and downstream license holders to make surplus facility capacity available to third parties, which would help integrate flare gas commercialization projects.
The Law on Gas and Gas Supply, 2012 , supports the government’s policy of increasing gas use across the country to avoid wasting the country’s natural resources and replace coal and other fuels with higher emissions. The national gas system operator KazTransGas, wholly owned by KazMunayGas, is also trying to reduce fugitive emissions across its transmission and distribution network. Since 2018, KazTransGas has used remote methane sensing, which identified 3,963 leaks by the end of 2020. Fixing these leaks will reduce methane emissions and avoid the waste of gas. Article 15 of the Law on Gas and Gas Supply, 2012, establishes the preferential rights of the state to purchase raw or processed (“commercial”) gas assigned to the operator under the upstream contract. KazTransGas is responsible for procuring the gas from upstream operators. Article 15 stipulates that the raw gas price can include the cost of recovering raw gas, the cost of delivering it to a location where KazTransGas can take possession, and a profit margin of no more than 10 percent. The price of commercial gas can also include the cost of processing. The National Energy Report, 2019, of the Kazakhstan Association of Oil, Gas, and Energy Sector Organizations (Kazenergy) suggests that the price paid by KazTransGas has not been sufficient to cover “the costs associated with recovering associated sour wet gas that must be gathered, processed, and transported to an injection point.” However, the price has been sufficient to cover the cost of delivering “shallow dry gas” to KazTransGas. According to the KazMunayGas 2020 Annual Report , five operating companies, in which KazMunayGas is a partner, sell their gas to KazTransGas under Article 15 of the Law on Gas and Gas Supply, 2012, and five others, including the Tengiz, Karachaganak, and Kashagan operations, sell gas directly to domestic and export markets or use it for re-injection or meeting their own heat and electricity needs. The 2020 Annual Report of KazTransGas acknowledges the need to increase wholesale prices to ensure the commerciality of domestic gas sales. It refers to a ministerial meeting in August 2020 that called for an annual increase of 15 percent between 2021 and 2026. Although domestic gas sales are twice as large as export volumes, revenues from domestic sales accounted for only 6 percent of revenues in 2018, mainly because regulated prices of gas delivered to customers have been kept artificially low. Phased increases of transport tariffs and retail prices, possibly based on netback pricing, are part of the strategic objectives of KazTransGas. Reforming gas pricing and sending the right price signals across the natural gas value chain are expected to provide incentives to reduce flaring further by offering a commercially viable alternative to upstream operators and serving the government’s gasification policy efficiently
The Pemex Law, 2008, created a new legal framework for the national oil company. At the same time, responsibility for upstream regulation was shifted to the CNH, and the functions of SENER and the Energy Regulatory Commission were strengthened. In 2013, amendments to Articles 25, 27, and 28 of the Constitution, 1917, were adopted. They allowed for the participation of private firms in activities previously reserved for the state. In 2014, additional transitory articles were signed into law outlining the main aspects of the secondary legislation needed to implement the different sector legislative changes. The Hydrocarbons Law, 2014 , updated in 2021, reemphasizes the role of Pemex and empowers SENER and regulatory agencies to suspend activities. Pemex or other state entities may be allowed to take over suspended activities. The 2014 secondary legislation created two bodies—the National Center for Control of Natural Gas (Centro Nacional de Control del Gas Natural) and the National Energy Control Center (Centro Nacional de Control de Energía)—to operate, monitor, manage, and coordinate the gas and electricity networks. The National Center for Control of Natural Gas was tasked with managing the old Pemex gas pipeline network. Pemex withdrew from natural gas transport, and private investors carried out a rapid expansion of the gas pipeline network. The pipeline transport capacity was tendered to interested shippers bidding through the open season process, and open access to the natural gas network was established. Interconnections with the US pipeline system were strengthened.
The Companies Income Tax Act, 1990 , provides incentives for the utilization of associated and nonassociated natural gas. Gas utilization is defined as the marketing and distribution of natural gas for commercial purposes and includes power generation, LNG, gas-to-liquid plants, fertilizer production, and gas transmission and distribution pipelines. Nigeria also adopted a gas transport network code in 2020, formalizing third-party access to critical gas infrastructure. The Petroleum Industry Act separates upstream, midstream, and downstream operations. Regulatory oversight of the upstream are transferred from the Department of Petroleum Resources to the Commission and regulatory oversight of midstream and downstream are transferred to the Authority (see section 6 of this case study), which has also assumed functions of the Petroleum Products Pricing Regulatory Agency, and the Petroleum Equalization Fund (Management) Board. Companies are required to create separate companies for each segment and acquire the necessary licenses from the Commission or the Authority. This structure and other provisions of the Petroleum Industry Act (see section 21 in this case study) are intended to promote natural gas production and utilization. According to Section 173 of the Petroleum Industry Act, the Authority will determine the domestic gas demand requirement for strategic sectors by March 1 of every year and inform the Commission of this requirement. As per Section 110, the Commission is responsible for ensuring compliance of every lessee and can charge a penalty of US$3.50 per million British thermal units for failure to comply. This penalty and implementation of the domestic gas obligation can be modified by the Commission according to the guidelines provided in Section 110 and other sections of the Petroleum Industry Act. As per Section 167, unless lessees sign agreements with buyers from the strategic sectors, the Authority will determine the domestic base price for gas, which “must be of a level to bring forward sufficient natural gas supplies for the domestic market on a voluntary basis by the upstream petroleum industry” under the Third Schedule of the Petroleum Industry Act. Under Section 39 of the Companies Income Tax Act, 2020, up to five years of tax holiday is available to developers of new gas pipelines.
Section 59 of the Regulations to Act Relating to Petroleum Activities, 1997 , grants operators undertaking downstream natural gas activities and eligible customers the right to access pipeline networks. The access is subject to the quality of the gas being compatible with technical specifications or efficient operation of the pipeline network. The pipeline network operator may require additional conditions after consulting with existing users of the pipeline network.
Natural gas consumption has been increasing in Oman, primarily to generate electricity and run desalination plants but also for use in downstream refining and petrochemicals facilities. Oman is a significant exporter of LNG, but it also imports pipeline gas from Qatar to balance domestic demand with export obligations. However, with increased investment in gas fields and, to a lesser extent, more aggressive policies toward capturing associated gas, Oman intends to phase out imports and expand domestic pipeline infrastructure. Low domestic gas prices have presented a challenge to achieving the goal of supplying gas for domestic purposes from domestic sources. The MEM and the Oman Gas Company have supplied gas to industrial and power generation plants at prices set by a gas allocation committee, which includes representatives of the MEM and the Ministry of Commerce, Industry, and Investment Promotion (the Financial Affairs and Energy Resources Council before August 2020). These prices, as well as the price of electricity (which is almost exclusively generated by gas-fired power plants), have been below cost. The government of Oman raised natural gas prices to industry and power generation plants, but low oil prices after 2016, especially in 2020, stressed the government’s budget and slowed further price reforms. The Energy Development Oman was created as a company that could raise capital at a lower cost than the government and undertake major energy transition projects . The Oman Gas Company, along with eight other state-owned companies across the oil and gas value chain, is now part of OQ, created in 2019. The newly integrated company is fully government-owned, but a partial public offering of shares is under consideration, as the government continues to focus on its budget deficit. The net effect of the changes cited in this section on domestic gas consumption, the development of new gas pipelines, and associated gas utilization will become apparent over the coming years.
Article 27 of Federal Law No. 69-FZ on Gas Supply, 1999 requires owners and operators of transmission and distribution facilities to give associated gas preferential access to free capacities. Article 32 of Federal Law No. 35-FZ on the Electric Power Industry, 2003 gives electricity produced from associated gas preferential access to the wholesale market.
As noted earlier in the case study, the MGS is a large system that gathers associated gas and delivers it to various end-users via a pipeline network of more than 4,000 km. As of early 2023, 7 gas processing plants, 2 natural gas liquid units, and 50 gas-oil separation plants complemented the network. The MGS midstream infrastructure, developed primarily by Saudi Aramco since the 1970s, ensures the utilization of associated gas for power generation, industrial activities, and other end uses. The Royal Commission oversees the downstream operations hosted by industrial cities; regulations, standards, and investments are coordinated across upstream, midstream, and downstream as well as across Aramco, Royal Commission, and other government entities.
Liberalization of the UK natural gas market began in the mid-1980s. There is wholesale and retail competition in this highly liquid market. Natural gas suppliers have regulated open access to midstream and downstream infrastructure. Timely development of this infrastructure is necessary to avoid delays in upstream production or flaring. If there is a need for new capacity, suppliers can develop new infrastructure or transact with independent midstream companies to develop the needed infrastructure. Companies operating in the natural gas midstream and downstream need a license from the independent regulator Ofgem. Offshore producers need to develop infrastructure to deliver their associated gas to the national gas system. This infrastructure includes pipelines, terminals, processing plants, and storage facilities, some of which are located onshore. If relevant, the OGA issues flaring and venting consents for these facilities. Environmental regulators have jurisdiction over these facilities as well as the rest of the national gas system.
The intention of the gas capture plan mentioned in Rule 903(e) of the Environmental Impact Prevention 900 Series, 2021 , is to ensure the beneficial use of the gas in the future. In areas with a limited pipeline network, the beneficial use requirement has led to solutions for gas that would otherwise have been flared. (Also, see section 24 of the case study on US federal onshore production.) In November 2022, the AQCC adopted a recovered methane rule as Part C of Regulation 22. The rule includes protocols for methane recovery projects from livestock manure management systems, municipal solid waste or landfills, wastewater treatment, coal mines, and gas utility system leaks.