The main characteristic of the Argentine hydrocarbon regime is that the state (ie, the federal government or the provinces) owns the hydrocarbons in the subsoil. The rights the state grants for the exploration and exploitation of hydrocarbon reserves are separate from surface ownership. The hydrocarbons, once extracted, belong to the entity or entities holding the relevant E&P rights.

The National Constitution, as amended in 1984, provides in Article 124 that “the eminent domain of the natural resources existing in their respective territories belongs to the provinces”. The provision became effective when Law 26,197, which was enacted in 2006, amended Law 17/319 (the “Hydrocarbons Law”), in accordance with Article 124. Therefore, as per the current Hydrocarbons Law, hydrocarbons belong to the provinces where they are located, or to the nation if the resources are located in federal territory. As a result, the nation only owns the hydrocarbons in offshore blocks in the continental shelf located more than 12 nautical miles away from the shore. Each province owns the hydrocarbons located in its territory, including those within 12 nautical miles of the shore.

This means the relevant state (ie, nation or province) that owns the resources has full authority to award E&P rights for the exploration, development and exploitation of said resources, including exploration permits, exploitation concessions and association agreements with state-owned companies. The state is also the enforcement authority regarding such awards and contracts.

The State Secretariat of Energy is the main governmental body involved in energy regulation at a national level. The Undersecretariat of Hydrocarbons and Fuels is the subdivision specifically devoted to oil and gas. The federal regulator is governed by the Hydrocarbons Law (as amended) and several executive orders issued by the national executive power. The secretariat is regulated from an administrative organisational standpoint by the Ministries Law, as restated by Decree No 438/92 (as amended), which establishes the different ministries, secretariats and functions assigned to each of them; see Ministry of Economy: Energy.

Each oil and gas-producing province has its own oil and gas regulators. Provincial regulators are governed by the federal Hydrocarbons Law and by provincial legislation. The local legislation in some provinces includes provincial hydrocarbons laws that are mostly in alignment with the Hydrocarbons Law, which provides the basic principles and substantial rules governing petroleum activity.

National policies regarding the exploration, development, production, transportation and marketing of hydrocarbons shall be determined by the national executive branch, according to the Hydrocarbons Law. This means that the power to establish national hydrocarbons policy and pass material legislation remains with the federal government and Congress, even though the provinces retain:

• ownership of the hydrocarbons;
• the power to grant permits and concessions; and
• regulatory powers concerning the way in which the federal hydrocarbons regime is applied in their territories.

The Hydrocarbons Law co-functions with hydrocarbon laws and regulations passed by particular oil and gas-producing provinces, such as the Province of Neuquén Hydrocarbons Law No 2453, the Province of Mendoza Hydrocarbons Law No 7526, the Province of La Pampa Hydrocarbons Law No 2675 and the Province of Chubut Hydrocarbons Law No XVII No 102, which are for the most part substantially aligned with the provisions of the Hydrocarbons Law. 

The Ente Nacional Regulador del Gas (Enargas) regulates most aspects relating to the transportation, distribution and marketing of natural gas.

The main oil and gas company controlled by the state is YPF SA, which is a sociedad anónima (stock company) governed by General Companies Law No 19/550 and therefore subject to the general legislation that applies to private companies. As per Law 26/741 (passed in 2012), whereby the controlling shares of YPF were expropriated from Repsol, the national government and petroleum-producing companies own 51% of the shares, of which 51% are owned by the federal government and 49% by the provinces. The provinces and the national government act jointly as though they were one shareholder but follow the national government’s lead. The remaining 49% of the shares are listed in the Buenos Aires Stock Exchange and also traded in international stock exchanges, such as New York, and privately owned.

As a sociedad anónima formed under the General Companies Law, YPF is subject to the regulations generally applied to any other stock company, except for its control structure. 

Energía Argentina SA (formerly Integración Energética Argentina SA) (ENARSA) is another state-owned company whose main purpose is to administer natural gas and LNG imports and act as an intermediary in certain domestic natural gas purchase and sale transactions – that is, when gas is then used to supply the distribution and sub-distribution sectors. It holds exploration permits on two offshore blocks. Decree No 1976/22 granted the company a natural gas transportation concession for the new “President Néstor Kirchner Gas Pipeline” to be built between the cities of Tratayén (Province of Neuquén) and San Jerónimo (Province of Santa Fe).

The Hydrocarbons Law (as amended by inter alia Laws 26/197 and 27/007) contains the basic material legislation in relation to the exploration, development and production of hydrocarbons. The Mining Code, along with the Hydrocarbons Law, applies in connection with certain issues not included in the Hydrocarbons Law. The Hydrocarbons Law is supplemented by numerous executive orders and resolutions. There are no specific rules in connection with pooling and unitisation. The Hydrocarbons Law establishes, as a basic principle, that holders of concessions shall conduct operations in a reasonable manner and procure in a way that does not cause damage to any adjacent fields. This law provides that issues involving adjacent exploitations shall be resolved by the concessionaire’s agreement and that, if no agreement can be reached, the Secretariat of Energy shall establish the way in which the adjacent fields shall be exploited.

Law 24/076 outlines the basic regulations for the transportation, marketing and distribution of natural gas. Other important laws are No 24/145 (federalisation of hydrocarbons), No 26/659 (restrictions in connection with the E&P of petroleum in the continental shelf) and No 26/741 (establishes the achievement of petroleum self-sufficiency as a matter of national strategic interest and expropriates the controlling shares of YPF SA).

Surface Inspection Permits

A surface inspection permit grants the permit holder the right to conduct a surface survey on a certain area, including carrying out geologic and geophysical studies.

The primary data obtained from the surface inspection is delivered to the enforcement authority when the permit expires. The enforcement authority may then process said data, or have it processed by third parties, and may use it as deemed convenient for its own purposes. The information shall not be disclosed for two years following such delivery without the express consent of the party that performed the surface inspection, unless permits or concessions are awarded in the prospective zone.

The Ministry of Energy and Mining passed Resolution 197/18 in 2018, with a new set of regulations applicable to surface inspection permits on offshore areas – ie, areas beyond 12 nautical miles from the coastline. This resolution provides for a much longer term (eight years) than onshore permits and gives the permit holder commercial exploitation rights. These include the exclusive right to disclose (subject to a few exceptions) and commercialise the data obtained from the inspection activities on a non-discriminatory basis for two years after the permit expires.

Onshore surface inspections are rarely used. Offshore surface inspection activity has been and is being conducted by a few international companies with permits issued under Resolution 197/98 or by a pre-existing permit that was converted into a permit under the terms of Resolution 197/18, as mentioned above.

Surface inspection permits are granted by the relevant executive branch (federal or provincial, depending on where the hydrocarbons are located). Permits under Resolution 197/18 are granted by the federal government.

Exploration Permits

Exploration permits are granted by the relevant executive branch, which will be either federal or provincial, depending on where the hydrocarbons are located. 

The holder of an exploration permit has the exclusive right to perform exploratory activities within the permit area. They also have the exclusive right to obtain an exploitation concession upon discovering oil or gas in commercially exploitable quantities and conditions (commercial discovery) during the term of the permit.

Exploration permits are awarded through a bidding process. As in similar processes, this involves the submission of two envelopes. Envelope A must contain evidence of the bidder’s experience and technical and financial qualifications, whereas envelope B is the economic offer itself. The latter typically comprises work commitments and an entry bonus.

The blocks are awarded based on criteria that include the amount of work units, time of exploration commitments and, in some bids, the entry fee offered by the bidder. The public tender will be awarded to the bidder who makes the highest offer, in keeping with a formula that takes all the above-mentioned factors into consideration.

Exploitation Concessions

Exploitation concessions grant the exclusive right to exploit the area’s existing hydrocarbon fields. They are granted by the relevant executive branch, which is either federal or provincial, depending on where the hydrocarbons are located.

The exploitation of a field involves the development of its potential. The Hydrocarbons Law requires concessionaires to produce as much hydrocarbon as possible using rational and efficient techniques. By the same token, the exploitation concession also depends on the concessionaire’s ability to build and operate treatment plants, as well as having the other faculties necessary for these operations. This includes having the right to request a transportation concession to transport the production out of the concession area.

The hydrocarbons belong to the concessionaire, in accordance with its participating interest in the concession, and the concessionaire may dispose of its share of the production freely – subject to the general limitations contained in the Hydrocarbons Law and its supplementary regulations.

Association Agreements With Province-Owned Companies

The province-owned company typically owns the E&P rights in association agreements and makes such rights irrevocably available to the private party/parties involved in the joint venture.

The provincial company makes its exploration rights over the area available during the exploration stage. Should a commercial discovery occur, the provincial company must request an exploitation concession from the province and, once granted, make it available to the joint venture.

Typically, the province-owned company holds a 10% participating interest.

The private parties assume all the exploratory risk on an exclusive basis, as the province-owned company does not assume any investments, costs and expenses during the exploration stage. Following a commercial discovery and the subsequent grant of an exploitation concession on the block, the province-owned company must pay its share of capital and operating expenditures (CapEx and OpEx respectively). 

The hydrocarbons belong to each party as per its participating interest in the contract, and each party can dispose of its share of the production freely – subject to the general limitations contained in the Hydrocarbons Law and its supplementary regulations.

The private party (or one of the private parties if there is more than one) shall be the operator.

Surface inspection permits are granted by the relevant governmental authority following a request from a company willing to conduct such surface inspection.

Exploration permits are granted through public bidding rounds.

Exploitation concessions can be obtained:

• by the holder of an exploration permit for all or a portion of the exploration area, following a commercial discovery;
• through a public bid in connection with “proved” blocks (blocks where exploration activities are deemed unnecessary); or
• in the case of unconventional exploitation concessions, when the exploitation concession holder asks for the concession area to be subdivided based on the block’s unconventional potential and for the subdivided area with unconventional potential to then be granted an unconventional concession.

Association agreements with state-owned companies are granted through public bidding rounds called by the relevant provinces.

The following are some of the qualifications required to grant an upstream licence in a public bid. 

• Bidders must provide a bond to guarantee that the offer will not be withdrawn and – once the permit, concession or contract is awarded – the prevailing bidder must provide a bond to guarantee the proposed minimum work commitments will be fulfilled.
• A local entity is required – this can be a local company (a stock company or a limited liability company) or branch.
• The local entity must be registered with the E&P Companies Registrar of the Secretariat of Hydrocarbons, and with similar registrars in the relevant province.
• The company must show evidence of its financial capability (and also technical capability, if it is going to be an operator) in order to register. The financial capability requirement parameter (as set forth in Disposition No 335/19, issued in September 2019) currently stands at a net worth of at least:
1. the value in ARS of 27,000 barrels of crude oil for companies involved (or willing to be involved) in onshore activity; or
2. the value in ARS of 270,000 barrels of crude oil for companies involved (or willing to be involved) in offshore activity (where the average price of a barrel of crude oil is calculated based on domestic sales in the previous calendar year, as confirmed by the Undersecretariat of Hydrocarbons on its web page).
• The applicant’s financial and economic capability should be analysed using certain ratios applicable to evaluate the company’s financial and economic position.
• Specific financial and technical capability requirements for qualifying as a bidder were set forth in an international bidding round for offshore blocks that took place in the first quarter of 2019.
• Companies performing any E&P activities in the Falkland Islands (Islas Malvinas), or that have any affiliate involved in such activities, cannot register with the E&P Companies Registrar and therefore cannot hold any interests in any upstream licence.

Royalty on the production of hydrocarbons must be paid on a monthly basis to the relevant province or national government (in accordance with the location of the hydrocarbons field). Royalty is regulated by Sections 59 through 65 of the Hydrocarbons Law and by National Decree 1671/1969.

Royalties are a percentage of the hydrocarbons produced at wellhead (Section 59 Hydrocarbons Law). The Hydrocarbons Law provides for a 12% royalty on hydrocarbons produced under exploitation concessions and for a 15% royalty on hydrocarbons produced under an exploration permit. 

Article 27(3) of the Hydrocarbons Law, amended by Law 27/007, provides that the royalty can be reduced by up to 50% in tertiary production (enhanced oil recovery and improved oil recovery) and in extra heavy oil and offshore projects that, owing to their particular productivity issues and location, present particularly unfavourable technical and economic characteristics.

Royalty shall be paid in cash, unless the relevant province or national state asks to be paid in kind, and provided the producer ensures that hydrocarbons are received on a reasonably permanent basis. Therefore, royalty is calculated on the net price obtained for the production.

During the extension periods of concessions, an additional royalty of up to 3% can be added – with a total cap of 18%.

The royalty prescribed in law shall be the only government take calculated and received from production. 

However, in concessions that were extended before the enactment of Law 27/007 in 2014, extra payments for the production may apply, such as additional payments of up to 3% of the production. This also includes certain windfall profit payments, which are triggered when the prices obtained for hydrocarbons produced from the concession area exceed particular parameters.

Surface Fee

The Hydrocarbons Law establishes that holders of exploration permits and concessions must pay an annual fee (payable in advance in January), which is calculated for each square kilometre (km²) of the permit or concession area. These annual fees vary during the exploration phase, depending on the exploration period, as explained below.

In a basic exploration term, the fee is an amount equal to the value of 0.46 bbl of oil/km² for the first period and an amount equal to the value of 1.84 bbl of oil/km² for the second.

During an exploration permit’s extension period, the fee is an amount equal to the value of 32.22 bbl of oil.

Under exploitation concessions, the fee to be paid is an amount equal to 8.28 bbl of oil/km².

The value of a barrel of crude oil is calculated based on the average domestic price for the first semester of the previous year (published on the Secretariat of Energy’s website).

Extension Bonus

Law 27/007 allows for an extension bonus fee to be imposed when a concession extension is granted. The maximum bonus shall be equivalent to 2% of the average oil and gas price of the relevant basin’s proven reserves at the end of the concession’s term.

Social Programmes

Tender processes organised by the provinces for the granting of permits, concessions or association agreements to provincial state-owned companies usually include obligations to make social contributions. These can take the form of:

• donating an amount of money that the province can use to benefit communities local to where the company will carry out its operations;
• donating vehicles or computers that can be used to monitor activities by the hydrocarbons and/or environmental authorities;
• providing training for – or paying for the training of – certain public officials or employees of provincial state-owned companies; or
• contributions to provincial agencies or not-for-profit organisations (eg, provincial or national universities).

The amount of these social contributions has not been material vis-à-vis the amounts involved in the relevant E&P projects. 

The terms and conditions applicable to the extension of existing concessions or to bidding rounds for the award of upstream licences may – and usually do – contain an obligation to make certain contributions for the relevant province to use in the implementation of social or educational programmes.

Within the national jurisdiction, E&P companies are liable for the payment of all federal taxes generally applicable in the country (income tax, value added tax, debits and credits in bank accounts tax) and any applicable customs duties.

E&P companies are also liable for the payment of all provincial taxes (ie, gross income tax and stamp tax) and municipal taxes in force as of the date of the award. During the term of the permits and concessions, the provinces and municipalities shall neither levy new taxes upon the holders thereof nor increase the rate of pre-existent taxes – except for those rates paid towards the performance and improvement of services, or a general increase in taxes.

Federal Taxes

Income tax

Law No 27/630, published in the Official Gazette on 16 June 2021, modifies the Income Tax Law (Law No 20/628, as amended in 2019) with regard to corporations and permanent establishments. Consequently, the income tax rate will depend on the accumulated taxable net income as per the following:

• up to ARS5 million, a 25% rate will be applied;
• more than ARS5 million and up to ARS50 million, a 30% rate will be applied; and
• more than ARS50 million, a 35% rate will be applied.

The amounts provided for in the new scheme will be adjusted annually from 1 January 2022, taking into account the annual variation of the Consumer Price Index (IPC) compiled by the Argentine Institute of Statistics and Censuses (INDEC).

The net profit of individuals and foreign entities from dividends and profits will be taxed at a 7% withholding rate.

With a few exceptions, all expenses incurred in the process of obtaining and maintaining the income-producing source are deductible. Tax losses can be carried forward for five fiscal years. There is no carry-back.

Treaties designed to avoid double taxation are in force with Canada, Australia, the UK, Sweden, Bolivia, Germany, Brazil, France, Austria, Chile, Italy, Spain, Finland, Denmark, Belgium, the Netherlands and Norway. Argentina and the USA signed a treaty to avoid double taxation in 1981, but it has never entered into force.

Value-added tax

This federal tax is applied on the sale of goods, the rendering of services and the importation of goods at 21%. When purchasing goods, obtaining services or importing goods, registered taxpayers must pay an additional 21% on the price to the individual or entity selling the goods or rendering the services. The amount of VAT paid constitutes a VAT credit. When selling goods or rendering services, the registered taxpayers must charge an additional 21% on their prices. The amount so collected constitutes a VAT debit.

The difference between VAT credits and VAT debits must be paid to the Federal Internal Revenue Agency from time to time. VAT credits may be carried forward without a time limit.

Joint ventures and other sorts of associations are considered VAT taxpayers. Such associations and their members are viewed as separate entities for the purposes of VAT. 

Tax on financial transactions

This tax applies to any debit from – or credit to – bank accounts. The applicable rate is 0.6% of the amount of the transactions; 0.3% of the amounts levied on credits can be taken as advanced payment of income tax. 

Provincial Taxes

Gross income tax

This tax is applied to the gross income derived by entities or individuals that carry out economic activities within the territory of a province. The tax rates vary depending on the activity and the province, but generally range from 1% for primary activities to 3% for trading and 4% for financial activities or intermediation. If one activity is carried out in several provinces, the Multilateral Convention is applied, whereby the tax base is distributed among the provinces in order to prevent double taxation.

Stamp tax

Stamp tax is applied to agreements that are executed within the territory of a province or that produce effects in it. The tax rates vary depending on the sort of agreement and the province, but the applicable general rate ranges from 1% or 1.5% to 3.5% to 4% for certain transactions (such as the transfer of vehicles and real estate). Most fiscal codes specify that agreements will be levied with stamp tax when they are executed by the parties thereto or if they will have effects in the province. 

Export duty

Executive Order 488/20 states that export duties shall be paid on any exports of hydrocarbons or hydrocarbon by-products, in accordance with a mobile rates scheme. Pursuant to this scheme, the applicable rate will be:

• 0%, if the international reference price (Brent) is not higher than USD45;
• 8%, when the international reference price is higher than USD60; and
• determined by a certain formula, which takes into account the value of the international reference price at any given time, when the international reference price is higher than USD45 but not higher than USD60.

No special rights for national oil companies are granted in the applicable legislation. However, as mentioned in the section on association agreements with province-owned companies (2.1 Forms of Private Investment: Upstream), the provincial company is carried throughout the exploration stage in such agreements.

Section 71 of the Hydrocarbons Law states that companies performing jobs regulated by this law should hire Argentine nationals and, in particular, residents of the region where the works are to be carried out. The proportion of nationals employed by each concessionaire or permit holder shall not be less than 75%.

A similar provision is included in Section 94 of Neuquén Hydrocarbons Law No 2453. In practice, exceptions to the above-mentioned rule are accepted in the case of specialised workers that are not available in Argentina or the region where the operations are conducted.

Decree No 277/22 created a promotional regime to enable beneficiaries to access the foreign exchange market with proceeds resulting from incremental oil and natural gas production, providing they comply with the Regime for the Promotion of Employment, Labour and Development of Regional and National Suppliers of the Hydrocarbons Industry. The aim is to use entirely regional and national manpower, suppliers and service providers through two different schemes, namely:

• the Regional and National Integration Requirements Scheme; and
• the Preferences Scheme.

Holders of exploration permits must inform the relevant national or provincial authority about any petroleum discovery within 30 days. Moreover, once the permit holder determines the discovery is commercially exploitable, it has 30 days to request an exploitation concession, which must be granted within 60 days – provided that the permit holder has submitted the delimitation of the area.

The award of the concession does not affect the continuity of the exploration rights until the end of the relevant exploration periods on the portion of the exploration block that is not subject to the exploitation concession.

If, following the performance of exploration and/or evaluation works, the exploitation concession holder determines that all or part of the concession area has unconventional petroleum potential, they can request the grant of an unconventional exploitation concession on the relevant area. This is based on a pilot plan that should be submitted along with the request.

The authority must decide whether to grant the request within 60 days of its submission, provided that the concessionaire has supplied all the information deemed necessary to make such a decision – and to the authority’s satisfaction.

The province of Neuquén has imposed a specific regulation outlining the development plan requirements that need to be met in order to obtain unconventional hydrocarbons exploitation concessions. The regulation stipulates the need to include a pilot plan (and the methodology to determine the pilot plan area) and, once this has been completed, annual updates of the development plan to be approved by the province. 

There are no deemed approvals. A denial by the petroleum authority can be appealed through administrative recourse and eventually before a court of law.

As per the Hydrocarbons Law, the exploration periods are set forth in the terms and conditions that apply to each public bid, within the following maximum terms.

• For a permit with a conventional objective, there is a basic term of three years plus three years, plus an extension term of five years. In permits referring to offshore exploration, each of the periods of the basic term can be increased by one year.
• For a permit with an unconventional objective, the basic term is four years plus four years, plus an extension term of five years. 

At the end of the first period of the basic term, the permit holder shall be able to keep all the exploration area. This shall be relinquished at the end of the second period of the basic term – unless an extension is requested, in which case at least 50% of the area shall be relinquished.

The term of an exploitation concession is 25 years (or 30 years for offshore concessions). The term of an unconventional exploitation concession is 35 years.

Concessions can be renewed for ten-year periods and there is no limit on the number of renewals. However, a renewal must be requested no less than one year before the expiry of the current term and by concessionaires that are in compliance with their obligations under the relevant concession.

Extensions are not granted automatically but require governmental approval, so some negotiation is required in practice. As mentioned in 2.3 Typical Fiscal Terms: Upstream, extension bonuses that the provinces or nation can apply are capped by the Hydrocarbons Law.

Concessionaires can relinquish the concession areas at any time; in which case, they will have to comply with all accrued and pending obligations as of the relinquishment date and with the abandonment procedures set forth in the applicable regulations.

With regard to association agreements with province-owned companies, their most relevant terms and conditions are detailed in 2.1 Forms of Private Investment: Upstream.

Permit holders, concessionaires and holders of participating interests in association agreements own and have free access to their share of the petroleum substances produced from the relevant area, subject to the general limitations established in the applicable regulations (eg, secure adequate supply of the domestic market – see Section 6 of the Hydrocarbons Law).

According to Section 72 of the Hydrocarbons Law, exploration permits and exploitation concessions can be granted to those that fulfil the necessary financial and technical conditions and requirements, provided there is prior authorisation from the executive branch (federal or provincial, as applicable). 

Under Section 73 of the Hydrocarbons Law, a concessionaire can declare its interest in an exploitation concession as a security interest when it comes to obtaining loans to finance upstream operations in the relevant concession area. 

Provincial hydrocarbon laws contain provisions in line with the ones described earlier.

The assignment of participating interests in joint venture agreements with provincial E&P companies usually has to be approved by the board of the relevant province-owned company, and that approval must be ratified by the provincial executive branch.

Retained liabilities following a duly approved and consummated transfer of an upstream interest include any royalty and taxes accrued before the effective date of the transfer. In case of damage to property, individuals or the environment, retained liabilities towards third parties include those caused during the period in which the transferor held the upstream interest. This is irrespective of any indemnity provisions that the transferor may have agreed upon vis-à-vis the transferee. 

The transfer of any upstream licence is subject to the rules of Argentine antitrust law, so approval from the antitrust regulator might be required, depending on the specific circumstances of each transaction.

No legal or regulatory restrictions apply.

Private producers of petroleum – either liquid or gaseous – have a right, under the Hydrocarbons Law, to build transportation facilities to transport the production from the producing fields to the trunk pipelines transportation system and to obtain any applicable transportation concessions granted by the federal or provincial states. 

The system of transportation through the trunk pipelines can also be operated by private companies under transportation concessions for liquid hydrocarbons – and under transportation licences for gaseous hydrocarbons – for terms of between 25 and 35 years, which can be extended. Terminals and associated storage facilities are operated under the same transportation concessions previously referred to.

However, in a recent exception, the national state has directly granted a new trunk natural gas transportation concession to the state-owned ENARSA through Decree No 277/22. The operation and maintenance of this new facility will be carried out by a private company, under a contract with ENARSA.

The transportation of natural gas from the trunk pipelines to consumers is carried out by certain private companies that have been granted distribution licences by the federal government, and each of these companies has a monopoly within the area of its licence. There are no other governmental or private monopolies in the midstream and downstream sectors.

No specific restrictions apply to the construction of new facilities or the acquisition of participating interests in companies that refine, store and market fuels and other petroleum by-products. Decree 1,212/89 formed the basis of a system that, unlike previous regulations, allows the free construction of refineries and service stations by the private sector, subject to the technical and safety regulations that apply to such facilities.

There are no national monopolies (or near-monopolies) in downstream operations in Argentina.

Transportation concessions granted following the privatisation of companies that provided transportation services through the trunk pipelines system in the 1990s were awarded mostly to companies holding upstream licences. The Hydrocarbons Law states that such companies have a right to obtain transportation concessions directly so they can transport their production out of the production fields without a public bidding process. In order to obtain a transportation concession, the companies must comply with the applicable technical, environmental and safety requirements.

In other cases, a concession or licence to transport petroleum through new pipelines within the trunk system must be obtained through a public bidding process. Executive Order 115/19 (which amended Executive Order 44/91) empowered the Secretariat of Energy to launch public bidding processes for the grant of one or more liquid hydrocarbons transportation concessions.

The developer of a new pipeline – in addition to existing concessionaires looking to expand their transportation facilities – can sell and reserve firm capacity in advance at transportation tariffs that may be freely negotiated with transporters seeking to secure transportation capacity in the new facilities.

As mentioned in 3.1 Forms of Private Investment: Midstream/Downstream, the national state granted a new trunk natural gas transportation concession directly to the state-owned ENARSA through the issuance of the “urgency and necessity” Decree No 76/22. Urgency and necessity decrees rank pari passu with laws passed by the National Congress, provided certain requirements are met.

The construction by private companies of new refineries, storage plants and service stations does not require specific licences, provided that the following requirements are met before the start of operations.

• A municipal permit must be obtained from the relevant municipal authority, which will check that the facilities are in full compliance with the applicable health, safety and environmental regulations.
• The company must be registered with the Oil and Gas Companies Registrar, under its Refineries and Marketing Companies Section (Resolution SE 419/98 and supplementary regulations), or with the Registrar of Service Stations, Self-Consumption, Storage, Distribution and Wholesale Marketing of Petroleum and Natural Compressed Gas (Resolution SE 1,102/04 and supplementary regulations). Certain technical, legal and financial documents must be submitted to the Registrar for this purpose.

The income obtained by the operators of the petroleum trunk pipeline’s transportation system (including terminals) and certain storage facilities comes from the tariffs paid by the users of said services, in accordance with the rules applicable to the relevant concessions or licences. The rest of the midstream and downstream operations are conducted under freely negotiated commercial terms and conditions, including swaps authorised as non-physical transportation by Decree No 540/21.

With respect to midstream facilities constructed or expanded after the enactment of Decree No 115/19, the contracts for the transportation of liquid hydrocarbons typically provide for the contracting of firm capacity with Ship-or-Pay clauses. Midstream contracts are agreed based on maximum quantities and other variable commercial terms.

Last, supply of fuels to service stations is usually regulated by contracts with a duration not exceeding five or eight years, in which the suppliers, while authorising the use of their trade marks and commercial image, reserve the right to fix the prices applicable to the products marketed. 

The income does not incur any specific payment obligations towards the granting state, without prejudice to the obligation to comply with the general tax regime.

The same is true for companies that operate refineries, storage plants and service stations, which are subject only to the applicable tax regime.

The same federal, provincial and municipal taxes detailed in 2.4 Income or Profits Tax Regime: Upstream apply to the income or profits generated by the operation of pipelines, plants and retail and wholesale marketing. Although the tax stability guarantee at the provincial and municipal levels provided for in Law 17,319 does not apply to these sectors, licensees of natural gas transportation and distribution services may request of Enargas that any increase in the tax burden of the service be reflected in a corresponding variation in the tariffs they charge.

Tax on Fuels

In general terms, this tax is applied on the transfer (either for a consideration or not) and import of gasoline, gas oil, diesel oil, kerosene, crude naphtha, turpentine and solvent. 

Law 27/430, effective from January 2018, ensured this tax is no longer calculated as a percentage of sales, but rather as a fixed amount per the volume of products sold. Such fixed amounts are subject to periodical adjustments in accordance with the increase in the inflation rate.

The taxpayers are the refineries, traders (under certain conditions) and importers of the levied products. The transfer of levied products that are to be exported is exempted from the tax.

Tax on Carbon Dioxide

Law 27/430 replaced the tax on diesel oil with a tax on carbon dioxide, which is applied to the transfer (either for a consideration or not) of the above-mentioned fuels and also to fuel oil, coke and mineral carbon.

This tax is also calculated by applying certain fixed amounts (adjusted periodically in accordance with inflation) for each product, per measurement unit sold. 

Monitoring and Control Contributions

A monitoring and control contribution must be paid to the relevant government agency (Enargas) by the holders of gas transportation and distribution licences. The contribution is calculated relative to the cost of rendering such services and the gross income accrued by the relevant licence holder.

There are no national oil or gas companies holding special rights in connection with downstream licences.

Law No 27/437, which passed in May 2018 and established a preference regime for the acquisition of goods and services originating in the country, applies to a number of entities, including:

• governmental entities;
• state-owned entities; or
• entities holding public utility concessions.

This law also established an obligation for such entities to develop national suppliers when performing petroleum activities. Similar requirements could be applied at a local level (eg, provinces and municipalities).

The holders of petroleum transportation concessions under the Hydrocarbons Law must receive, transport and deliver the petroleum in a diligent and timely manner. If the transportation capacity is insufficient, the same shall be prorated among the chargers in proportion to the volume that each charger intends to inject into the system and taking into account the average volumes already loaded by them during the six-month period prior to the time when the capacity became insufficient.

Transportation systems must operate in a continuous and uninterrupted manner. The operators are responsible for the loss or deterioration of the petroleum transported, except for events of force majeure. 

Holders of licences for transportation through the trunk pipelines system and distribution of natural gas are bound by duties and obligations similar to the aforementioned. The tariffs to be paid by the users should allow the holders to bear their operational costs, taxes and amortisations, as well as make a reasonable profit. In practice, the system has oscillated between periods of government intervention in the mechanisms used for establishing tariffs and times where a gradual return to market prices was favoured.

Law 27/541 (passed in December 2019) and Executive Order No 1,020/20 (passed in December 2020) froze natural gas transportation and distribution tariffs and opened proceedings for the renegotiation of the terms and conditions set forth in the last Integral Tariff Review of 2017. The deadline for the completion of the renegotiation was extended by the Decree No 815/22 until December 2023.

Meanwhile, gas regulator Enargas approved a scheme of transitional tariffs that are to be adjusted on an annual basis and are significantly lower than the inflation rate registered during the relevant periods.

Pursuant to the Hydrocarbons Law, transportation concessionaires can reach an agreement with the surface landowners to develop activities on their surface land by paying them compensation for damages caused to their properties by said transportation activities. The amount of compensation can be determined by mutual agreement between the landowner and concessionaires or by the local court. 

If concessionaires cannot reach an agreement with the landowner, they are entitled to obtain an easement on the surface land from the competent enforcement entity, as the Hydrocarbons Law considers hydrocarbons activities to be of national interest. 

Pursuant to Law 24/076, natural gas transportation and distribution licensees have the same easement rights established in the Hydrocarbons Law.

The substantive regulations applicable to hydrocarbon transportation activity are sanctioned by the national state, as well as the rest of the substantive regulations applicable to the industry. Law 17,319 and Decree 44/91 (and its amendment by Decree 115/19) in the case of liquid hydrocarbons, as well as Law 24,076 and Decree 1738/92 for natural gas, are the rules that set the basis for the regulation of this matter.

The concessions for the transportation of liquid hydrocarbons applicable to facilities that transcend the limits of a province, or that are dedicated to export, are of national jurisdiction, under the terms of Law 26,197. In this case, the regulation and control are under the charge of the National Secretariat of Energy. In the rest of the cases in which the facilities are located entirely within the same province, the application authority is the Energy Secretariat or similar agency of the relevant province.

The activity of transportation and distribution of natural gas is under the control of Enargas, created by Law 24,076.

Petroleum transportation concessionaires must receive and transport petroleum substances from third parties on a non-discriminatory basis, including for a non-discriminatory price under the same circumstances, provided that there is still transportation capacity available in the pipeline after satisfying the concessionaire’s needs.

The maximum tariff that the concessionaire may charge to third parties is determined by the enforcement authority, in accordance with the terms of the concession. Where firm capacity was sold in advance to finance new pipelines (or the expansion of existing ones), the concessionaire’s open access obligation is limited to the portion of the transportation capacity that has not been reserved on a firm basis or that, despite having been reserved, is not used. Also, in such cases the tariff can be freely negotiated with transporters looking to secure firm transportation capacity in the new facilities. 

Holders of licences for the transportation and distribution of natural gas must guarantee third parties open access, on a non-discriminatory basis, to the remaining transportation capacity that has not already been committed as part of firm transportation agreements.

Producers, operators of storage facilities, distributors and users of the transportation system who purchase gas directly from the producers are banned from having a controlling interest in the holder of a gas transportation licence. Producers, operators of storage facilities and transporters who purchase gas directly from producers in the same geographic area as a distributor are also banned from having a controlling interest in said distributor.

There are no restrictions on the sale of oil by-products into the local market, provided that such products comply with the regulations regarding technical specifications and general fair trade and antitrust provisions. 

Holders of licences for the transportation of natural gas cannot purchase or sell it – unless the gas is purchased for their own consumption and necessary to keep the transportation system operational. Consumers in general must acquire natural gas from the distributor or sub-distributor serving each area, but large industrial consumers must purchase the fluid directly from the producers.

Crude oil exports must be offered to the domestic market first, as per the procedure outlined in Decree 645/2002, former Secretary of Hydrocarbon Resources Resolution No 241/2017 and Secretariat of Energy Resolution No 175/23.

Exports of gas require governmental approval in accordance with Section 3 of Law 24/076 and Secretariat of Energy Resolution No 360/21, as amended by Resolution No 774/22. The exports considered in this resolution are:

• firm exports, which are in turn subdivided into:
1. Plan Gas.Ar firm exports;
2. firm exports derived from additional injections during the winter within the Plan Gas.Ar; and
3. firm exports of surplus production in a basin;
• interruptible exports;
• operational exchanges (with a subsequent obligation to reimport the same volumes that have been exported); and
• assistance agreements.

Volumes for which an export authorisation is required must be made available to:

• ENARSA (the state-owned company that administers imports of natural gas and LNG);
• CAMMESA (a state-controlled company that administers the wholesale electricity market);
• power generators;
• distributors; and
• sub-distributors.

All volumes contemplated in the authorisation request must also be made available to the natural compressed gas sector, who will have a preferential right to purchase them under the same terms and conditions, provided the natural gas purchased is used to supply domestic demand. Authorisation requests for firm Plan Gas.Ar exports shall have priority vis-à-vis other authorisation requests.

Per Decree 488/20, exports of by-products are subject to the same scheme of export duties that applies to petroleum. The existence of the aforementioned preference and export duties results in a domestic price that is lower than the export price.

Although Law 17,319 provides for the possibility of regulating the conditions under which the importation of liquid hydrocarbons and by-products may be carried out to ensure the priority consumption of those produced in Argentina, there is currently no regulation in force in this regard. Law 24,076 authorises the importation of natural gas without the need for any kind of approval.

In connection with LNG requirements, please see 6.2 Liquefied Natural Gas (LNG).

Transfers of transportation concessions under the Hydrocarbons Law are subject to the authorisation procedure already prescribed in the context of upstream licences. Transfers of licences for transportation of gas through the trunk pipelines system require the national executive branch’s consent.

Enargas approval is required for any change in control of natural gas transportation and distribution companies subject to its jurisdiction. Before issuing an approval, Enargas will verify that the proposed change in control does not infringe any of the vertical or horizontal integration restrictions contained in the natural gas regulatory framework and that the financial and technical requirements will continue to be met after the proposed change in control.

Assets that are indispensable for the transportation or distribution of natural gas cannot be transferred without prior authorisation from Enargas.

No specific requirements apply to the transfer of other midstream or downstream licences or assets.

No foreign investment approvals or restrictions apply to investments in hydrocarbons. 

There are no specific foreign investment protections for investment in hydrocarbons. However, as a general principle, any foreign investor in Argentina has the same legal rights and guarantees as any domestic investor, owing to an “equal treatment” principle established by Article 20 of the National Constitution. 

With regard to stability provisions, the general principle is that nobody has a legal right to claim that a specific legal framework must remain unchanged. However, any beneficiary of contractual rights granted by the government pursuant to a specific regime shall be able to exercise such rights even after such regulations have been abrogated or amended. The rights are considered part of the patrimony of the beneficiary, and the wholeness of such patrimony is protected by law (Article 14 of the National Constitution and related regulations).

As an exception to the principle, the Hydrocarbons Law grants the holders of exploitation concessions a right to enjoy certain stability regarding provincial and municipal taxes.

The National Constitution acknowledges everybody’s right to use and dispose of their property. In addition, such property shall not be violated; although it can be subject to expropriation if:

• the “public use” of the property under expropriation is declared by law; and
• compensation (considering the actual value of the asset) is paid to the affected party prior to the transfer of ownership (Articles 14 and 17 of the National Constitution).

There are more than 60 bilateral investment treaties in force between Argentina and other countries.

Upstream licences are governed by Argentine law, and any disputes in relation thereto should be submitted to the jurisdiction of provincial or federal Argentine courts.

Arbitration – either national or international – can be agreed upon between private parties, including YPF SA (a stock company that is state-controlled but ruled by the regulations applicable to private companies). Although arbitration provisions were included in a few association agreements with private-owned companies some time ago, the rule now is that any disputes must be submitted to the provincial courts.

There are no sanctions in place with respect to investing in oil and gas assets in foreign jurisdictions or conducting business in the oil and gas sector with foreign counterparties or governments or in certain jurisdictions.

National Regulations

The hydrocarbons sector is governed at national level by general regulations containing minimum environmental protection standards – such as Law 25/675 (General Environmental Law) and Law 24/501 (Hazardous Waste Law) – and by general regulations and minimum standards specifically applied to hydrocarbon activities by the enforcement authority, which exercises powers delegated by the Hydrocarbons Law to that effect. Such authority is held by the Secretariat of Energy, currently within the scope of the Ministry of the Economy. Other regulations could also be issued by the Secretariat of the Environment and Sustainable Development and Enargas. 

The main applicable regulations include the following.

• Policies and procedures for the protection of the environment contained in Resolution SE 105/92, which:
1. requires the submission of a prior environmental study before drilling the first exploratory well and beginning to develop the reserves;
2. provides for the annual monitoring of works and tasks; and
3. sets out detailed technical guidelines to be followed in the exploration and exploitation of hydrocarbons.
• Annual Environmental Monitoring Reports – Resolution SE 25/04 defines and describes the technical characteristics, structure and scope of environmental studies and annual environmental monitoring reports. 
• Contingency plans and information about incidents must meet the guidelines provided under Resolution SE 342/93, and the enforcement authority must be informed within the deadlines and satisfactory to requirements established by Resolution SE 24/04.
• Emission (“venting”) of gas to the atmosphere – Resolution SE 143/98 establishes guidelines and mandatory limits on this matter and the certain justified circumstances in which such limits can be exceed.
• Safety conditions for transport – Resolution SRH E No 120/17 approved the Technical Regulations for Transportation of Liquid Hydrocarbons by Pipeline, which applies to pipelines and ancillary facilities subject to a transportation concession and Disposition 123/06 of the Undersecretariat of Fuels provides for the Environmental Protection rules applicable to them.
• The set of technical rules named NAG 100 and NAG 153 of Enargas are the technical regulations that apply to the transportation of natural gas by pipelines. In particular, NAG-153 provides for criteria and minimum requirements for: (i) identifying and quantifying environmental impacts; (ii) establishing preventive and corrective measures in relation to such impacts; and (iii) establishing common parameters for the preparation of environmental assessments and reports required for different stages of a project.
• Safety conditions and maintenance of storage tanks of crude oil and by-products – Decree 10,877/60 describes the active and passive defences to be implemented in these facilities and Decree 2407/83 provides for the security rules to be followed by service stations and other operators in the downstream sector. Resolution SE 785/05 created the Programme for the Control of Spills from Surface Storage Tanks, which established that companies with such facilities have to register and inspect such tanks. Companies must also comply with a maintenance plan, report any incidents and report the abandonment of the tanks.
• Safety auditing service – Resolution SE 419/93 and other supplementary regulations obligate refineries, storage companies and operators of service stations to hire safety auditing services to certify compliance with the applicable safety regulations on an annual basis.

Provincial Regulations

The provinces have the authority to supplement federal regulations with local regulations, as long as they do not overstep the principle of federal law pre-eminence established by Section 31 of the National Constitution. Provincial regulations have been passed establishing regimes for environmental matters such as:

• gaseous emissions control;
• subterranean water exploitation;
• groundwater exploitation; and
• pressurised devices control.

An environmental study must be prepared prior to the development of a new project and submitted to the relevant (provincial or national) environmental enforcement authority. Upon the approval of the study, the operation can begin and the operator must comply with recommendations, restrictions and conditions (if any) contained in such approval (Resolution SE 105/92 and related regulations).

Additionally, the operator must:

• obtain an authorisation for the use of water in the project, which should include the origin of the water and the conditions under which it shall be used;
• register with the National Hazardous Waste Generators Registry; and
• be issued an Annual Environmental Certificate (Law 24/051, Decree 831/93 and other regulations).

Joint Resolution No 3/19, issued by the Secretariat of Energy and the Secretariat of Environment and Sustainable Development, was published in the Official Gazette on 27 November 2019. It outlined a set of rules governing the environmental impact assessments to be conducted in connection with exploration and exploitation activities in the continental shelf, subject to federal jurisdiction (beyond 12 nautical miles from the coastline).

The proceedings potentially include a public hearing, in accordance with the rules established in Law 25/675 (General Environment Law).

Resolution 5/96, issued by the Secretariat of Energy, established rules and procedures for the abandonment of oil and gas wells, including a timetable for the abandonment of certain wells.

On an annual basis, the operator should report the decommissioning works performed in the past year and those to be performed in the following year. Four years before the respective concessions expire, or as of the date all or part of an exploitation block is relinquished, the concessionaire must submit a technical and economic study explaining the reasons why the abandonment of each inactive well might be inconvenient.

Recommended techniques for performing definitive abandonment are detailed in the same resolution. The technical conditions that apply to the abandonment of gas pipelines and ancillary facilities are established in resolutions NAG 100 and NAG 153 of Enargas. The abandonment of these facilities requires prior consent from Enargas, which will evaluate whether there is a general interest in keeping the facilities operative.

On the other hand, the conditions for the temporary closure and eventual removal of tanks, pipelines and other related facilities for the storage and dispatch of hydrocarbons and by-products are regulated by Resolution 1102/04 of the Secretariat of Energy.

There is no requirement to pay any costs associated with the abandonment of wells and facilities. 

Although not regulated specifically, the non-operator owner of an interest in an upstream licence or transportation concession can be held liable in connection with abandoned assets by third parties (including the enforcement authority) in the event of non-compliance with the applicable decommissioning obligations. Even after fully divesting an ownership interest, the former owner of the asset similarly may be liable towards third parties if there is evidence that it breached an obligation to carry out abandonment works before such divestiture, and that the breach resulted in damage to the environment.

Argentina has ratified:

• the United Nations Framework Convention on Climate Change (UNFCCC) (Law 24/295);
• the Kyoto Protocol (Law 25/438); and
• the Paris Agreement (Law 27/020). 

Certain actions have been taken in Argentina to align with the objectives of such conventions (although they do not specifically enforce them). These measures include:

• enacting a regime that promotes the production of biofuels by establishing that fossil fuels commercialised in the country must be blended with biofuels, in proportions that have been increased gradually (Law 27,640 and other supplementary regulations); and
• modifying the technical specifications of fossil fuels (including a reduction in the maximum sulphur content in fuel oil and diesel oil used in power generation) to reduce the emissions of substances that cause acid rain and particulate matter (Resolution SRH No 5/16).

As described in 5.1 Environmental Laws and Environmental Regulator(s), the power to issue basic rules on environmental matters that apply to the whole country rests with the federal state (congress and executive branch). However, the provinces may supplement the federal regulations with local regulations, provided that they do not overstep the principle of federal law pre-eminence established by Section 31 of the National Constitution.

The amendments made to the Hydrocarbons Law by Law 27/007, passed in 2014, included several provisions specifically related to unconventional resources. As previously discussed, these include longer exploration periods and the creation of an unconventional exploitation concession with a longer term and the possibility of annexing a field adjacent to an unconventional concession area where there is geological continuity. 

The amendment to the collective bargaining agreement for the Neuquén Basin set forth certain rules that were designed to achieve more efficient operations and reduce labour costs, specifically in unconventional operations. As a result, a similar amendment was entered into regarding the collective bargaining agreement for the Austral Basin.

There is no special scheme relating to LNG projects in force yet. However, in order to create the conditions that would allow one or more companies to invest in the liquefaction and LNG export facilities needed to market the increasing unconventional gas production, both the government and the industry concur that certain specific regulations will be required sooner or later. To such end, an LNG projects regime bill was sent to the Congress by the National Executive in June 2023. The bill has not been discussed yet.

Secretariat of Energy Resolution No 706/21, issued on 23 July 2021, created the LNG Operators Registry and set forth regulations applicable to short- and long-term LNG exports. Per this resolution, LNG exports that are not subject to a long-term export permit must be offered to the domestic market first.

Energy transition issues are not affecting the development and use of oil and gas upstream and midstream assets yet. Preliminary studies show Argentina’s potential for carbon capture, utilisation and storage (CCUS) projects involving underground storage in hydrocarbons wells. One study estimates that the Neuquén Basin could be able to store the CO₂ emissions generated by thermal power plants in the provinces of Buenos Aires, Córdoba, Mendoza, Neuquén and Río Negro (which account for most of the total thermal generation CO₂ emissions in the country) for 15 years. There is not a specific regulatory framework on CCUS yet. Most of the existing CCUS projects in Argentina relate to forestation developments such as the project started a decade ago by Novartis.

Notwithstanding the lack of specific government laws, programmes or incentives focused on incentivising greenhouse gases reduction (such as tax credits) the fact is that most of the mid-size and large operators have been implementing measures to that effect, such as using electricity generated from renewable sources (mostly wind and solar) to supply their operations’ needs. Due to the country’s underground carbon storage potential mentioned above, several industry players have pointed out the convenience of pass legislation establishing a new carbon storage concession, to be granted on depleted hydrocarbon wells.

Argentina’s shale gas resources would be enough to supply its domestic demand for approximately 200 years, largely exceeding the time required to complete the global energy transition to a zero-emissions energy matrix. Something similar is happening on a smaller scale with the country’s shale oil resources.

As result of the extraordinary developments made in operational, technical and cost-efficiency matters over the past ten years, Vaca Muerta has become a world-class, proven shale play in terms of productivity. The resource is there, the learning curve to exploit adequately has been successfully completed and several blocks are undergoing massive development of their shale resources, while many others are undergoing their pilot stages.

The main obstacles to the massive and timely development of the country’s shale resources are the lack of sufficient infrastructure and stringent foreign exchange restrictions that discourage investment and financing of projects. These are being dealt with by expanding the existing midstream facilities and implementing certain exceptions to foreign exchange restrictions. 

In such respect, the following projects are worth mentioning.

• The construction of the 585-kilometre first stage of the President Néstor Kirchner natural gas pipeline, with an 11 cubic metre/day capacity, was successfully and timely completed by ENARSA, owner of the transportation concession, which used two main contractors, Techint (which laid the larger portion of the pipeline) and SACDE. Transportadora de Gas del Sur (TGS) was contracted as operator through a bidding process in which only it and Transportadora de Gas del Norte were invited to participate.
• The works for the expansion of the Oldelval pipeline and Oiltanking Ebytem storage and shipment facilities, crucial to market the increasing Vaca Muerta oil production, are being executed and are schedules to be completed by the second semester of 2024. These expansions are being carried out by the private companies holding the existing transportation concessions under the open season scheme established by Decree No 115/19, whereby freely negotiated firm capacity contracts are signed between the carrier/terminal operator and the shippers.
• The Trasandino Pipeline, used to export crude oil from Argentina to Chile, operated by a company owned by YPF, Enap and Chevron, resumed operations after being idle for more than 16 years.
• Other midstream projects in the pipeline of state-owned and private companies include the second 467-kilometres stage of the President Nestor Kirchner gas pipeline, the reversion of the north gas pipeline to take gas produced in Vaca Muerta to northern Argentina in order to replace the declining imports from Bolivia, and a new oil pipeline that will run from southern Vaca Muerta to a new terminal in the Province of Río Negro for the transportation of between 30,000 and 120,000 cubic meters/day of crude oil.
• The promotional regime for the petroleum industry created by Decree No 277/22 was complemented by Decree No 484/23 and Secretariat of Energy Resolution No 13/23, and is already being used by producers. This regime enables each company obtaining incremental production – when compared with a certain base production and taking into account the company’s total domestic production – to access the foreign exchange market using up to 20% (or more, depending on particular requirements being met) of the proceeds from its sale for the purpose of paying dividends abroad and/or repaying external debt, including debt with affiliates.
• A bill containing an incentives regime for LNG projects was sent to Congress by the National Executive in June 2023. The regime contemplates incentives for the whole value chain, including dedicated fields and midstream infrastructure needed to feed the LNG liquefaction plant or plants to be built. The benefits include free availability of 50% of export proceeds, which would be used by the beneficiaries to pay dividends, repay financial and commercial debt or repatriate direct investments by non-resident shareholders, as well as the possibility to opt for an accelerated amortisation of investment (for income tax purposes) and a simplified mechanism for obtaining the reimbursement of VAT paid in connection with investments in LNJ projects. The bill also contains foreign exchange and fiscal stability provisions. Although the regime is reasonably good, it will not be easy to have the bill discussed at Congress during 2023, with primary elections, general elections and, eventually, a ballotage, scheduled between August and November. However, it is expected that this bill (as currently written or with certain amendments) will be passed into a law sooner or later, as this is a condition precedent agreed upon between YPF and Petronas in a Memorandum of Understanding in relation to a potential large LNG project that both companies signed in 2022.
• On the offshore exploration side, it seems that finally, after struggling for years with injunctions ordered by a federal court at the request of Green Peace and other entities and individuals, Equinor will be able to start the drilling of the first deepwater well and a 3D seismic campaign in blocks located 300 kilometres away from the city of Mar del Plata.

Besides the regulations mentioned in 6.4 Unique or Interesting Aspects of the Hydrocarbon Industry, there have not been any material changes in oil and gas law or regulations during the past 12 months. Simultaneously with the submission of the LNG projects incentive regime bill sent to Congress, another hydrogen incentives regime bill was submitted. The bill contemplates benefits for green, blue and pink hydrogen.