Country
Assessment
According to Article 127 of the Environmental Code, 2021 , emission taxes are calculated using base levies for various emissions, including those from flaring, provided in tax laws. For example, according to Article 576 of the Tax Code, 2017 , base tax rates for emissions from flaring are 20–278 times as large as the same emissions from other stationary sources. Paragraph 8 of Article 576 states that local authorities may increase the tax rates up to 200 percent of the base rate, except for emissions from flares, which can be increased to more than 200 percent of the base rate. Recent changes to the Tax Code align it with the Environmental Code, 2021. According to Article 575 of Law No. 402-VI, 2021, the base tax rates for emissions from stationary sources will be doubled from January 2025, and emissions from flaring will be assessed at the same rate as stationary sources. Article 130 of the Environmental Code, 2021, provides tax relief to facilities that obtain an integrated environmental permit through the adoption of the best available techniques (see section 13 of this case study). Penalties will be heavier for facilities that do not adopt the best available techniques.
Paragraph 11 of the Petroleum Profits Tax Act, 1958 , provides incentives for gas separation and treatment investments by making such investments deductible against revenue. The incentives were extended to nonassociated gas in 1999, and therefore they are no longer specific to associated gas. The Petroleum Industry Act repeals the Petroleum Profits Tax Act, 2018, for new acreages. Section 39 of the Companies Income Tax Act, 1990, provides large fiscal incentives for gas utilization. The section offers the following benefits: an initial tax-free period of three years, renewable for an additional two years, or an additional investment allowance of 35 percent accelerated capital allowance of 90 percent a year after the tax-free period and an additional capital allowance of 15 percent without reducing the asset value tax-free dividends during the tax-free period if the investment is in a foreign currency and imports are not less than 30 percent of the company’s equity share capital the deductibility of loan interest payments, provided the minister of petroleum resources approved the loans. Section 104 of the Petroleum Industry Act (footnote 9) states that fines paid for flaring are not eligible for cost recovery and are not tax deductible. Section 264 disallows the deduction of “expenditure incurred as a penalty, natural gas flare fees or imposition relating to natural gas flare” for the “purpose of ascertaining the adjusted profit of a company in the accounting period from its upstream petroleum operations applicable to crude oil.” Section 260 exempts production of associated and nonassociated natural gas from the new hydrocarbon tax; it allocates costs of producing associated gas to crude oil as a deduction in calculation of the hydrocarbon tax. Part IV, Section 10(6) of the Seventh Schedule sets the royalty for natural gas utilized in-country at 2.5 percent versus 5 percent for all other natural gas and natural gas liquids. Royalties are applied to chargeable volumes as defined in Part III, Section 7(5) of the Seventh Schedule and exclude “volumes burned, flared or vented with the approval of the Commission.”
The main instruments for restricting GHG emissions—emissions trading and the carbon dioxide tax— are economic; they provide financial incentives to minimize emissions. Norway was one of the first countries in the world to introduce a carbon tax, in 1990. Sections 1, 2, and 4 of the CO2 Tax Act, 1990 , require a carbon dioxide tax payment for flared or vented natural gas and any other carbon dioxide discharged to the atmosphere during the production and transport of oil and gas unless otherwise exempted by the Storting (Parliament). The operator calculates, reports, and pays the total tax amount to the NPD on behalf of all other licensees. The operator provides the NPD with the documentation for metering petroleum and calculating the tax within a month of the expiry of each term. If the tax is not paid on time, it accrues interest. According to Section 3 of the CO2 Tax Act, 1990, the carbon dioxide tax is not deductible from the calculation of the production fee (defined in Section 4 of the Norwegian Petroleum Act, 1996 . According to Norway’s Climate Action Plan, the government may consider the introduction of a tax on methane emissions from onshore petroleum facilities, corresponding to the tax that already applies to offshore activities. For 2023, the tax rate is proposed at NKr 1.78 (about US$0.16 as of June 2023) per cubic meter (m3) of gas or per liter of oil or condensate. For emissions of natural gas, the tax rate is NKr 13.67 (about US$1.24 as of June 2023) per m3. For combustion of natural gas, the rate is equivalent to NKr 761 (about US$69 as of June 2023) per tonne of carbon dioxide (tCO2). The companies also pay European Union Emissions Trading System (EU ETS) allowance costs. The Norwegian government proposes to gradually raise the total cost of carbon (the Norwegian carbon dioxide tax and the cost of EU ETS allowance) to NKr 2,000 (about US$181.4 as of June 2023) per tCO2e by 2030.
Chapter 7 of the Oil and Gas Law provides several provisions with respect to natural gas. Article 41 requires the concessionaire to preserve natural gas and allows its exploitation, with MEM approval, to enhance oil recovery, store it underground, commercialize it, or use it for any other purposes as decided by the MEM. Article 42 provides for “features, incentives and facilities to encourage gas exploitation” to be stipulated in the concession agreement. For example, the concessionaire is allowed to recover gas discovery expenses if the MEM decides to postpone production to meet future domestic market demand.
Fees related to gas flaring and venting are not tax-deductible. However, legal entities participating in several oil and gas projects across the value chain could benefit from fiscal consolidation, allowing them to offset profits from one project against losses from another. Depending on how profitable the other operations are, doing so could enable the utilization of associated gas, which would otherwise be flared or vented.
No evidence of fiscal incentives to reduce emissions was found.
If flaring or venting occurs without the required approval, or the BSEE regional supervisor determines that the operator was negligent or could have avoided flaring or venting, the hydrocarbons are considered avoidably lost or wasted and subject to royalties (12.5 percent in old leases, 16.67 percent in shallow waters, and 18.75 percent in deep water), according to Title 30 CFR § 1202. Operators must value any gaseous or liquid hydrocarbons avoidably lost or wasted under the provisions of Title 30 CFR § 1206. Fugitive emissions from valves, fittings, flanges, pressure relief valves, or similar components do not require approval under this subpart unless specifically required by the regional supervisor. The BSEE Resource Conservation Section is responsible for informing the ONRR about noncompliance with regulations resulting in a loss of hydrocarbons from flaring or venting that could have been avoided and the volumes involved. Section 50263 of the Inflation Reduction Act declares that, for all federal leases issued after August 16, 2022, royalty is due on all produced gas except “(1) gas vented or flared for not longer than 48 hours in an emergency situation that poses a danger to human health, safety, or the environment; (2) gas used or consumed within the area of the lease, unit, or communi̬tized area for the benefit of the lease, unit, or communi̬tized area; and (3) gas that is unavoidably lost.”
According to NTL-4A , unavoidably lost production (see section 9 of this case study) is exempt from royalty calculations. BLM officers may determine that lost production was caused by failure to comply fully with the applicable lease terms and regulations, or appropriate provisions of the approved operating plan. Avoidable losses are subject to royalty. Set by law in 1920, the minimum royalty rate on federal onshore is 12.5 percent. The BLM’s 2016 Waste Prevention Rule introduced several conditions that create additional incentives. For example, it detailed the economic justification necessary for operators to demonstrate that capture is uneconomic and introduced a limit of 10 mmcf per well a month. Above this limit, the BLM may determine that gas is avoidably lost and hence subject to royalty. The 2016 rule also required that an action plan show how the operator will minimize the flaring or venting of the oil-well gas within one year. An operator may apply for approval of an extension of the one-year limit. If the operator fails to implement the action plan, the entire volume of gas vented or flared during the time covered by the action plan is subject to royalty. The BLM rescinded these requirements in 2018. Under the proposed rule, with the APD requirement (see section 11 of this case study), qualification as unavoidably lost production is expected to be more difficult.
NDAC Section 43-02-03-60.3, 2014 , states that any operator seeking to have a well certified for purposes of eligibility for the gas tax incentive provided in North Dakota Century Code Section 57-51-02.6 should apply for certification as an oil or gas well employing a system to avoid flaring. Gas is exempt from tax for 2 years and 30 days from the date of first production if either of these conditions is met: The gas is used at the well site to generate electricity, and at least 75 percent of the gas is consumed. The gas is collected at the well site by a system that takes in at least 75 percent of the gas and natural gas liquids volume (more than 50 percent of propane and heavier molecules) for beneficial consumption, such as the production of petrochemicals or fertilizer. The gas tax rate was as high as US$0.18 per thousand cubic feet (mcf) in 2009 and 2010. It was reduced in 2015. In July 2021, it was set at US$0.04 per mcf. In June 2023, the tax rate was set at US$0.1423 per mcf until June 30, 2024.
Article 104 of the Organic Law of the Environment, 2006 provides three types of economic or fiscal incentives, which could in principle be applied to flaring reduction: a state-financed credit system exemptions from the payment of taxes, fees, and contributions any other legally established economic or fiscal incentive. These incentives will be granted to persons who invest in preserving the environment according to the terms established in Article 102. The incentives aim to promote the adoption of clean technologies, environmental management systems, conservation practices, and the sustainable use of natural resources, as stated in Article 103.