According to Article 210 of Law No. 19-13, 2019 , there is a tax on flared volumes. This tax is nondeductible for the purposes of calculating other payments under the upstream fiscal regime. The tax is 12,000 Algerian dinars (about US$90 as of September 2021) per 1,000 cubic meters (m³). ALNAFT can adjust this tax at the beginning of every year based on the national inflation index. The tax increases by 50 percent if an operator flares without authorization (except for flares for safety reasons as stated in Article 159) or flares more than the volumes allowed in the authorization (Article 213). According to Article 215, the tax is not due under the following conditions: during exploration activities or well testing during the start-up period, the duration of which is set by ALNAFT or ARH in the absence of capacity for gas recovery or takeaway (pipeline) infrastructure at facilities built before 2005. According to Article 11 of Executive Decree 21-330, 2021 , in case of delays in the start-up of new facilities, the national company or contractors must include a justification along with a request for permission to extend flaring; additional volumes flared will be subject to tax. Article 21 stipulates the same requirements for flaring at midstream facilities and Article 26 for venting during pipeline transport. Article 29 requires that an annual declaration to the fiscal authority on flare taxes must include all information necessary to calculate the taxes. According to Article 30, ALNAFT and the ARH are required to provide the fiscal authority a report on each flaring operation. The report must include actual flared volumes.

The Angola Liquefied Natural Gas Project (ALNG) is the first LNG project in Angola. It uses associated natural gas, helping to reduce gas flaring and associated greenhouse gas emissions. Daily capacity is 1.1 billion cubic feet (bcf). Decree 10/2007 created a special legal regime for the ALNG that includes specific maritime, tax, customs, and foreign exchange regimes. The ALNG is subject to a specific tax regime under which sponsor entities hold a tax credit of 144 months starting from the date of initial commercial production, deductible against the profit income tax. The ALNG is subject to a quarterly gas tax from the first LNG export shipment date. Decree 7/2018 provides more attractive tax rates to gas operations. The gas production tax is 5 percent (compared with 10 percent for oil). PSCs state that any surplus gas produced by oil companies that is not used for field use must be given free of charge to Sonangol (see section 5 of this chapter). The capital expenditures borne by companies for the storage and delivery of associated gas to Sonangol are cost recoverable. Sonangol will manage the gas infrastructure once commissioned and will also bear the cost of operating it. Should funding the gas infrastructure have a significant negative impact on the economic conditions agreed to in the PSCs for the contractor, Sonangol is required to modify the economic terms of the contract to restore the contractor’s economic position before the gas infrastructure project.

Section 8 of Annex 1 of Resolution 143/1998  states that as a condition for granting the exception to gas venting, the licensees must provide a guarantee of investments in emission abatement within 15 calendar days from the notification of the approval to the company. The amount of the guarantee depends on the emission flows during the exception period and the abatement investments to be made. Guarantees are set for each project by semester or as a fraction of the exception period and of the investment to be made. The guarantee will be called if the company does not execute the agreed investments for each project at the expiration of each term.

According to Section 10 of the Offshore Petroleum (Royalty) Act, 2006, royalty is not payable if the Western Australia state minister “is satisfied that the petroleum has been flared or vented in connection with operations for the recovery of petroleum” and flaring and venting did not contravene the OPGGS Act, 2006 , and associated regulations. In Queensland, according to the Petroleum and Gas (Production and Safety) Act, 2004 , an operator is exempt from paying petroleum royalty if the revenue commissioner is satisfied that the volumes flared or vented were part of exploration drilling (Section 591). The exemption applies to gas flared or vented during the production testing period but only up to 3 million cubic meters (Section 591A). As per Section 926, petroleum royalty is not payable for volumes flared or vented if approval was given under the Petroleum Act, 1923, before December 31, 2004. In Western Australia, according to the Petroleum and Geothermal Energy Resources Act, 1967, and the Petroleum (Submerged Lands) Act, 1982 , operators may apply to the DMIRS for exemption from royalty payment for petroleum that—with the minister’s approval—is flared or vented in connection with petroleum recovery operations. Under New South Wales’ Petroleum (Onshore) Act, 1991 , royalty is not payable if the minister approves gas flaring or venting (including of gas or other forms) for operations connected with petroleum recovery (Section 87). In South Australia, according to the Petroleum and Geothermal Energy Act, 2000 , royalty is not payable if petroleum or any associated substance is “destroyed or dissipated in accordance with sound production practice” (Part 7). In Tasmania, security deposits are required and must be high enough to cover environmental liability.

According to Law 9847/1999, the volume of gas flared under the responsibility of the concessionaire will be included in the total volume of production used for calculating royalties. The royalty rate is typically 10 percent but can be as low as 5 or as high as 15 percent. Royalties on oil and gas production are fully tax-deductible.

In 1998, the government of Alberta announced the Otherwise Flared Solution Gas Royalty Waiver Program. Flaring gas that could be economically conserved makes the gas ineligible for a royalty waiver. The waiver is independent of the end-use of the gas and lasts for 10 years. Companies are also exempt from royalties if gas is used for on-site power generation. The gas royalty rate is 5 percent during the cost-recovery period, after which the royalty rate is a function of the reference gas price and production level. According to Directive 060, 2020 , gas conservation economics should account for royalties paid for incremental gas that would otherwise be flared or vented. If the economic evaluation results in a net present value of less than Can$55,000 (about US$40,400 as of May 2023), the operator should reevaluate the gas conservation project on a before-royalty basis. If the evaluation results in a net present value of Can$55,000 or more, the operator should proceed with the conservation project and apply to the AER for an “otherwise flared solution gas” royalty waiver.

British Columbia has fiscal incentives in place to induce the lease use or marketing of associated gas. There are two broad classifications for calculating natural gas royalties: conservation gas and nonconservation gas. Conservation gas is natural gas that has been produced as part of oil production that is conserved and marketed instead of flared. All other gas is considered nonconservation gas. Section 5 of the Oil and Gas Royalty Handbook, 2014 , shows how royalties are calculated under various gas prices and well classifications. Royalties paid for conservation gas are often as low as 8 percent, compared with up to 27 percent for nonconservation gas. This difference in royalty rates creates an incentive for producers to capture and market associated gas. In addition, according to Section 5.9 of the handbook, natural gas or by-products used for production, drilling, or re-injection are exempt from royalties and production taxes. Gas lost is also exempt from royalty and tax if the regulator deems that the loss is not the fault of the producer and the producer does not receive any compensation for the loss (for example, insurance proceeds). The lost gas includes flared and vented volumes.

Associated gas that is flared or vented within permitted levels is not subject to royalties. According to the Administrative Procedures Related to Associated Gas Royalties/Taxes and Crude Oil and Natural Gas Royalty/Tax Factors Information Circulars, companies are exempt from royalties if royalties make gas production uneconomic. In addition, any gas used for on-site power generation is exempt from royalties. The gas royalty rate may be as high as 12 percent, depending on the type of gas well and the production rate of the well. SaskEnergy is launching a new Associated Gas Conservation Program to create more opportunities in the upstream sector for the sale and movement of methane between oil production facilities for on-site use. The Saskatchewan Petroleum Innovation Incentive provides a royalty credit for commercial innovation projects new to Saskatchewan that can better manage GHG emissions. The Oil and Gas Processing Investment Incentive offers transferable royalty or freehold production tax credits at a rate of 15 percent of eligible program costs to value-added projects across all oil and gas industry segments such as gas-gathering transport infrastructure and methane gathering projects. The Oil and Gas Conservation Regulations, 2012 , allow operators to build pipelines to capture associated gas as qualifying conservation projects to avoid paying penalties.

No evidence regarding fiscal and emission reduction incentives could be found in the sources consulted.

No direct evidence regarding fiscal and emissions reduction incentives could be found in the sources consulted. However, for operators in the European Union, the regular publication of penalties and infringements per operator could serve as an incentive (see section 19 of this case study). For importers, Article 27 requires reporting their products’ methane footprint (see section 16 of this case study).