Argentina: Energy: Oil & Gas

Yes, since the first discovery of oil in 1907 in the Province of Chubut the oil and gas activity has developed until becoming an established industry, including the upstream, midstream and downstream sectors.  There are five producing basins in the country, the Neuquén, Golfo San Jorge, Cuyana, Austral and Northwest basins.

During the last 113 years, the upstream industry went through several schemes and systems, from a monopolistic ownership of the hydrocarbons by the state-owned company Yacimientos Petrolíferos Fiscales S.E. (predecessor of YPF S.A.) to the deregulation years during which YPF was privatized and the current scenario, in which YPF is a stock company governed by the General Companies’ Law No. 19,550 and listed in the stock exchange, in which the Argentine federal state and the hydrocarbons producing companies own 51% of the shares, that coexist and compete with several local and international companies that own exploration and production rights in onshore and offshore blocks. More than 150 companies are registered with the Upstream Companies Registrar held by the federal Secretariat of Energy.

During the last twelve months the country produced an average of 81 Mm3/day of oil and 130 MMm3/day of natural gas. The production of unconventional oil (77% of the total oil production) and unconventional gas (43.5% of the total gas production) have been increasing steadily, in contrast to the decreasing production of conventional oil and gas from mature fields. The country’s shale oil recoverable resources are the fourth largest in the world, while its shale gas resources are the second largest worldwide, with the Vaca Muerta formation being the most promising and prolific shale play so far.

As of the end of 2019, the country’s registered reserves of crude oil were 284,144 Mm3 (proved), 161,387 Mm3 (probable), 76,976 Mm3 (possible) and 157,502 Mm3 (resources), while its reserves of natural gas were 376,719 MMm3 (proved), 142,822 (probable), 95,087 (possible) and 383,135 (resources).

Exploration and production rights are granted by the issuance of superficial survey permits (used lately for offshore operations, rarely used onshore), exploration permits and exploitation concessions by the relevant province or by the national state, depending on where the hydrocarbons are located. Exploration and production rights can also be enjoyed by way of association agreements with state-owned provincial companies under which the state-owned company, as owner of the exploration and exploitation rights, make such rights available to the joint venture, while the private company undertakes the operation of the field, assumes all exploration costs and risks and owns its share (typically a 90%) of the production.

In general terms, the superficial survey, exploration permits and exploitation concession regime is the same for both onshore and offshore, although there are certain differences, such as, (i) longer terms for offshore superficial survey permits, (ii) longer exploration and exploitation terms for the offshore, if compared with conventional onshore permits and concessions, (iii)  higher financial capability requirements to register as an offshore upstream company, (iv) specific environmental impact assessment and environmental license regulations applicable to offshore seismic acquisition, and (v) potential reduction of the royalty rate applicable to the production from offshore fields.

Superficial survey permits give the permit holder the non-exclusive right to conduct exploration activity – excluding drilling of wells) within the permit area during the permit term (the maximum term is two years for onshore and eight years offshore permits) and the exclusive right, during the term of the permit and two years thereafter, to market the data obtained.

Exploration permits give the permit holders the exclusive right to carry out exploration activity within the permit area. The exploration terms provided for by the federal Hydrocarbons Law No. 17,319 (the “Hydrocarbons Law”) are: (i) for permits with a conventional objective, a basic term of three years plus three years, plus an extension term of five years; (ii) in permits referring to offshore exploration, each of the periods of the basic term mentioned in (i) can be increased by one year; and (iii) for permits with an unconventional objective, the basic term is four years plus four years, plus an extension term of five years. The holders of exploration permits (which are granted through bidding rounds) must comply with the minimum work commitments assumed in the bids submitted (typically, acquisition and processing of seismic data during the first period and drilling of at least one exploration well during the second period) and will be able to conduct any exploration activity in addition to those commitments. The permit holders have the exclusive right to apply for an exploitation concession if they make a commercially exploitable discovery within the permit area.

Exploitation concessions can be granted through bidding rounds (on areas with proven resources), upon a request made by an exploration permit holder that made a commercially exploitable discovery or, in the case of unconventional hydrocarbons exploitation concessions, by request made by the holder of a conventional hydrocarbons concession if the concessionaire determines that all or a portion of the field has unconventional potential. The concession terms provided by the Hydrocarbons Law are, (i) twenty-five years for onshore conventional concessions, (ii) thirty-five years for onshore unconventional concessions, and (iii) thirty years for offshore concessions. Concessions can be extended for an unlimited number of ten-year periods, subject to certain conditions. Concessionaires own the hydrocarbons produced from the concession area and can market them freely, subject to certain limitations (for example, exports restrictions that apply when the domestic demand is not sufficiently supplied).

Association or production sharing agreements with provincial state-owned companies are awarded through bidding rounds. Typically, the state-owned company holds a 10% interest in the contract, while the private party holds the remaining 90%. The state-owned company is the owner of the E&P rights and make them available to the joint venture while the private company undertakes the operatorship and assumes all costs and risks relating to the exploration activities.

Yes, Argentina’s large unconventional hydrocarbon resources are being exploited, especially the shale oil and gas resources in the Vaca Muerta formation, with several blocks undergoing full development or pilot stages.

The Hydrocarbons Law, as amended by Law 27,007 in 2014, contains several provisions specifically related to unconventionals, including longer terms for exploration permits with an unconventional objective and a specific unconventional hydrocarbons exploitation concession, with a longer term than the one applicable to conventional hydrocarbons concessions. Unconventional hydrocarbons exploitations concessions can be requested by the holder of an exploration permit with an unconventional objective, upon the occurrence of a commercial discovery, or by the holder of a conventional exploitation concession, on all or a portion of the concession area, upon determining that all or a portion of the conventional concession area has unconventional potential. The law also provides that the permit or concession holder asking for an unconventional hydrocarbon exploitation concession can request to annex a field adjacent to the unconventional concession area when there is geological continuity.

The main federal governmental body involved in energy regulation is the Secretariat of Energy, answerable to Ministry of Economy. The Undersecretariat of Hydrocarbons and Fuels is the secretariat’s subdivision specifically devoted to oil and gas and has five national directorates: Hydrocarbons Economy, Exploration and Production, Transportation and Measurement of Hydrocarbons, Refining and Marketing and Liquid Gas.

At a provincial level, 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 and regulations. In some provinces, the local legislation includes provincial hydrocarbons laws that are mostly aligned with the provisions of the Hydrocarbons Law, which provides the basic principles and substantial rules governing the oil and gas activity.

The government is not involved in the oil and gas industry directly, although YPF S.A. (the largest producer) is controlled by the national state, which, together with the oil producing provinces, hold 51% of its shares. The provinces and the national government act jointly as if they were one shareholder, following the leading role of the national government. The remaining 49% of the shares are listed in the Buenos Aires Stock Exchange and also traded in international stock exchanges, like New York, and privately owned. YPF S.A. is a stock company governed by the General Companies Law No. 19,550.

Some provinces have state-owned oil and gas companies that have been assigned certain upstream assets which, in most cases, are explored and exploited through association agreements with private companies, as described above.

Foreign companies willing to act as upstream companies in Argentina have to register a branch or a subsidiary in the country, which branch or subsidiary shall be subject to the rules generally applicable to all upstream companies, either controlled by local or foreign shareholders.

The branch or subsidiary will need to register with the national and relevant provincial upstream companies’ registrars. In order to register, certain financial and technical (for companies wishing to register as operators) capability requirements must be met. Currently, the financial capability parameter to be met in order to register with the national registrar (as set forth in Disposition No. 335/19) is, (a) a net worth of at least, (i) the amount of AR$ equivalent to 27,000 barrels of crude oil for companies involved (or willing to be involved) in onshore activity; or (ii) the amount of AR$ equivalent to 270,000 barrels of crude oil for companies involved (or willing to be involved) in offshore activity; in any case considering the average price obtained from domestic sales of oil produced in Argentina for the previous calendar year, as informed by the Undesecretariat of Hydrocarbons on its web page. Both the financial and technical capability requirements can be fulfilled with guarantees and technical assistance commitments, respectively, typically provided by affiliate companies.

It is worth mentioning that companies that directly or through an affiliate perform or have performed activities in the Argentine continental shelf (including the Malvinas / Falkland Islands area) without authorisation from the Argentine government cannot register as an oil company in Argentina, and thus cannot hold an upstream interest or be an operator.

At the national level the hydrocarbons sector is governed by regulations that apply generally to any industry, 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 applicable to hydrocarbon activities issued by the relevant enforcement authorities (Secretariat of Energy and Secretariat of the Environment and Sustainable Development).

The key features of the applicable environmental, health and safety regime include:

(i) The submission of a prior environmental study before drilling the first exploratory well and commencing development of the reserves, (ii) the annual monitoring of works and tasks, and (iii) the duty to observe certain environmental guidelines in the exploration and exploitation of hydrocarbons (Resolution SE No. 105/91);

(ii) The environmental studies and annual monitoring reports must comply with certain structure and scope, as described in Resolution SE No. 25/04. The environmental studies include four phases: an initial environmental status; an identification and characterisation of environmental effects and prioritisation of environmental impacts; an environmental impact mitigation plan; and a monitoring plan.

(iii) Exploration and exploitation activities in the continental shelf subject to federal jurisdiction (beyond 12 nautical miles from the coastline) are governed by certain specific rules contained in Joint Resolution No. 3/19, issued by the Secretariat of Energy and the Secretariat of Environment and Sustainable Development. Every holder of a superficial inspection permit, exploration permit or exploitation concession willing to carry out an exploration or exploitation Project, in the terms of Annex II of the resolution, shall comply with certain environmental impact proceedings and obtain an Environmental Impact Statement to be issued by Secretariat of Environment and Sustainable Development.

(iv) Whenever an environmental incident occurs, contingency plans must meet the guidelines provided under Resolution SE o. 342/93, and the enforcement authority must be informed within the deadlines and in the manner established by Resolution SE No. 24/04.

(v) Venting of gas to the atmosphere is subject to certain guidelines and mandatory limits set forth in Resolution SE No. 143/98.

(vi) Storage of crude oil and by products in tanks is subject to safety and maintenance regulation contained in Decree No. 10877/60, which describes the active and passive defences to be implemented in the facilities, and Resolution SE No. 785/05, which established a Programme for the Control of Spills from Surface Storage Tanks.

The rules contained in federal laws and regulations can be supplemented with local regulations, provided that they do not overstep the principle of federal law pre-eminence established by Section 31 of the National Constitution. In this regard, provincial regulations have been passed in connection with several environmental matters, such as a gaseous emissions control regime, subterranean water exploitation regime, groundwater exploitation regime, pressurised devices control regime, etc.

The government take in connection with oil and gas resources include a surface fee, calculated on the relevant exploration permit or exploitation concession area, and royalties, calculated as a percentage of the production. Both the surface fee and the royalty are paid to the relevant jurisdiction (province or national state) where the field is located.

The surface fee is payable annually, in advance, during the month of January. The fee is calculated by each square kilometre of the permit or concession area and the amount to be paid varies for each period during the exploration phase.

The applicable maximum surface fees, as set forth in Decree No. 771/20, are the amounts equal to the value of, (i) 0.46 barrels of crude oil per square kilometer, during the first exploration period, (ii) 1.84 barrels of crude oil per square kilometer during the second exploration period, (iii) 32.22 barrels of crude oil per square kilometer during the extension period of the exploration phase, (iv) 8.28 barrels of crude oil per square kilometer during the exploitation period. The price of crude oil to be used for the calculation is the average domestic price for the first semester of the previous year, published by the Secretariat of Energy on its website.

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. Royalties are paid on a monthly basis.

Considering particular circumstances relating to productivity issues, location and especially unfavourable technical and economic characteristics, in tertiary production (enhanced oil recovery and improved oil recovery), and in extra heavy oil and offshore projects, the royalty can be reduced by up to 50%.

Royalty shall be paid in cash, unless the relevant province or national state requests to be paid in kind, and provided the producer is ensured that hydrocarbons will be 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 an aggregate total cap of 18%.

The royalty provided in the law shall be the only government take calculated on the production.

Government take can also adopt the form of extension bonuses, payable when a concession is extended, which is subject to certain cap provided for in Law 27,007, and contributions to social programmes required by bidding and concession extension specifications.

The right to export is subject to the general principle contained in article 6 of the Hydrocarbons Law, which provides that, when the production of hydrocarbons is not enough to supply the domestic demand, the hydrocarbons produced in the country shall be used to secure such adequate supply of the domestic market. In line with the aforementioned, crude oil exports have to be offered to the domestic market first in accordance with the procedure provided for in Decree No. 645/2002 and Secretary of Ministry of Energy and Mining Resolution No. 241/2017. Exports of gas require governmental approval in accordance with Section 3 of Law 24,076 and former Ministry of Energy Resolution No. 104/18. The exports contemplated in such resolution are (i) long-term firm exports, (ii) short-term firm exports, (iii) long-term interruptible exports, (iv) short-term interruptible exports, (v) warm season exports (October to April), and (vi) exports required to deal with emergency situations or operational issues, with a subsequent obligation to reimport the same volumes that have been exported.

As regards local content, article 71 of the Hydrocarbons Law provides that companies performing jobs regulated by such law shall prefer to hire nationals and, particularly, residents of the region where the works shall be performed, and that the proportion of nationals employed by each concessionaire or permit holder shall not be less than 75%. A similar provision is included in article 94 of Neuquén Hydrocarbons Law No. 2453. In practice, exceptions to the abovementioned rule are accepted in connection with specialised workers that are not available in Argentina or in the region where operations are conducted.

The Province of Neuquén has issued regulations that establish an obligation to acquire a minimum of 60% of the contractual amount from companies based in Neuquén, which is calculated on an annual basis, in respect of each item or type of activity. This preference must be observed if the economic offer submitted by the Neuquén company is up to 7% greater than the best offer submitted by the other companies, provided that the Neuquén company accepts to reduce its prices to match the best offer received (Neuquén Law No. 3032).

Yes, the rules and procedures applicable to the abandonment of wells are set forth in Resolution SE No. 5/96. Per this resolution, operators shall report, on an annual basis, the decommissioning works performed in the past year and those to be performed in the following year. Four years before the expiration of the respective concessions, or as from the date of relinquishment of all or part of an exploitation block, the operator must submit a technical and economic study explaining the reasons why the abandonment of each inactive well could be inconvenient. The resolution also contains certain recommended definitive abandonment techniques.

ENARGAS (the national gas regulator) resolutions NAG 100 and NAG 153 establish technical rules applicable to the abandonment of gas pipelines and ancillary facilities. The abandonment of these facilities requires prior consent from ENARGAS, which will evaluate whether there is a general interest in keeping the facilities operative.

Producers of hydrocarbons – 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, when the pipeline extends beyond the limits of the relevant exploitation concession, to obtain a transportation concession granted by the federal or provincial states, as applicable. In order to obtain a transportation concession, the companies must comply with the applicable technical, environmental and safety requirements.

The system of transportation through the trunk pipelines (“pure” transportation concessions, as opposed to transportation concessions associated to an exploitation concession), can 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.

Concessions for the transportation of liquid hydrocarbons trough the trunk pipelines system must be obtained through a public bidding process. Executive Order No. 115/19 (which amended Executive Order No. 44/91), empowered the Secretariat of Energy to launch public bidding processes for the grant of one or more liquid hydrocarbons transportation concessions. Such executive order also provides that, in order to facilitate the financing of new petroleum transportation projects, the developer of a new pipeline, as well as an existing concessionaire willing to expand its transportation facilities, may sell and reserve firm capacity in advance, at transportation tariffs to be freely negotiated with the transporters willing to secure transportation capacity in the new facilities.

The transportation of natural gas through the trunk pipelines system is made under natural gas transportation licences granted under Law 24,076 and shall be obtained by a public bidding process too.

The transportation of natural gas from the trunk pipelines to consumers is carried out by distributors that have been granted distribution licences by the federal government, and each of these companies has a monopoly within the area of its licence.

Although there is not a specific and comprehensive regulatory regime for LNG, there are regulations applicable to regasification and liquefaction, and to receiving terminals.

Res SE No. 338/12 sets forth, (i) the rules applicable to the location of port terminals to be used for LNG operations and certain environmental requirements applicable thereto; (ii) technical regulations applicable to the design and construction of port infrastructure to be used in LNG operations; and (iii) safety requirements applicable to the interface between methane vessels and terminals. The resolution provides that terminals shall obtain certificates in connection with the design, equipment and construction or assembly thereof, issued by a classification society member of the International Association of Classification Societies Ltd., and sets forth an annual HSE monitoring regime applicable to such terminals.

ENARGAS Resolution No. 722/19 approved the Rules Applicable to the Storage of Natural Gas which includes, within the category of gas storage companies, the onshore regasification and liquefaction terminals, as well as onshore LNG storage facilities. These rules provide that all such companies must register themselves as well as their facilities with a specific registrar (the Gas Storage Registrar of the Argentine Republic) in order to carry out their activities (including liquefaction and regasification). Each company willing to register shall provide evidence showing that it is a skilled and experienced operator, or that it has hired an operator that meets such requirements. The resolution also establishes that the HSE regulations contained in Resolution SE No. 338/12 shall be of subsidiary application.

ENARGAS technical rules NAG-501, approved by ENARGAS Resolution No. 235/18, contains a set of minimum safety rules for onshore LNG storage facilities.

There are no permanent regasification or liquefaction terminals in Argentina. So far, regasification and, in small quantities, liquefaction, has been carried out by floating facilities. Preliminary projects for the construction of an onshore liquefaction facility or for the assembly of smaller scale modular liquefaction plants are being analysed, in order to provide an LNG market for the excess gas that will probably be produced from Vaca Muerta in the short to mid-term.  The eventual construction of an onshore facility will require a specific regime, or at least a set of rules that provide the assurances (in term of dedicated production and transportation capacity) and incentives (tax incentives, foreign exchange free availability regime) needed by investors and financing providers in order to engage in a project of such magnitude and long return of investment term.

Gas storage is one of the activities included in Law 24,076 and thus subject to the general provisions contained therein and to the jurisdiction and control of ENARGAS. However, Law 24,076 does not contain specific regulations applicable to gas storage. Decree No. 1738/92, that regulates and supplements the general principles and rules contained in Law 24,076, provides that gas storage shall be subject to the regulatory powers and monitoring of ENARGAS in connection with HSE issues only. Resolution No. 722/19, mentioned above in 13, which approved the Rules Applicable to the Storage of Natural Gas applies to LNG and non-LNG storage. Non- LNG storage categories include storage of compressed natural gas and pressured natural gas, as well as subsoil storage in depleted fields, salt caverns, aquifers and coal bed methane. Then, the obligation to register with the Gas Storage Registrar, meet the operatorship requirements, comply with the information regime and the subsidiary application of the HSE rules contained in Resolution SE No. 338/12 shall apply to non-LNG storage.

In February this year CGC began to operate the first subsoil storage project in the country, in the Province of Santa Cruz. Gas transportation facilities and terminals include storage facilities.

Yes, there is. The natural gas trunk transmission and distribution systems are regulated by Law 24,076 and several supplementary regulations, and subject to the jurisdiction of the ENARGAS. Transmission through the trunk system and distribution are carried out by private companies holding licences granted by the federal government. The law keeps transmission and distribution separate and prohibits vertical integration between both sectors.

Producers, operators of storage facilities, distributors and users of the transportation system that purchase gas directly from the producers are banned from having a controlling interest in the holder of a gas transportation licence. Also, producers, operators of storage facilities and transporters that purchase gas directly from producers in the same geographic area where a distributor operates are banned from having a controlling interest in such specific distributor.

The natural gas trunk transmission system is operated by two licence holders, Transportadora de Gas del Norte (TGN) and Transportadora de Gas del Sur (TGS), which are the result of the privatisation of the state-owned company Gas del Estado in the early nineties. The system has eight interconnections with transportation systems of adjacent countries, two with Uruguay, one with Brazil, four with Chile and ne with Bolivia. The distribution to consumers is made through a grid comprised of eight distributors, each of them serving an exclusive area.

Transportation and distribution rates are determined in the terms of the relevant licence and adjusted or revised periodically by ENARGAS.

Transportation through the trunk pipelines system can be made under firm transportation conditions, to which end they shall reserve certain capacity for the charger requiring such firm services, or under an interruptible services condition, subject to the actual available capacity in the system. The tariffs to be paid by the users, in accordance with Law No 24,076, should allow them to bear their operational costs, taxes and amortisations, and to obtain a reasonable profit. In practice, the system has oscillated between periods of government intervention in the mechanisms applicable to establish tariffs and others in which a gradual return to market prices was favoured.

Law No. 24,076 provides that holders of licences for the transportation and distribution of natural gas must guarantee third parties open access, on a non-discriminatory basis, subject to available capacity (the capacity that has not been already committed in relation to firm transportation agreements).

Yes, there is a competitive downstream gas market in which the natural gas produced by numerous holders of exploitation concessions (several private companies and YPF, the state-controlled stock company that competes with the rest of the market) is sold to distributors, to CAMMESA (the company that administers the wholesale electric market) and to end consumers. Residential consumers, commercial retail consumers and small industrial consumers purchase their gas from the distributors of their respective areas. Gas to supply the wholesale electric market is purchased through CAMMMESA. Industrial consumers can buy gas directly from the producers.

Domestic gas prices are a mix of regulated and market prices. The Ministry of Energy Resolution No. 46/17, as amended by Resolutions No. 419/17 and No. 12/18, established a subsidies programme to stimulate investments for the development of production of natural gas from unconventional reservoirs in the Neuquén Basin. Pursuant to this scheme, a guaranteed minimum price of US$7.50/MMBtu applied during 2018, and, thereafter, it will decrease US$0.50 per year until it reaches US$6/MMBtu in 2021. On 31 December 2021, the programme will end and prices should match import parity values. The difference between the minimum guaranteed prices and the actual market prices will be paid to the producers by the federal government. A few projects qualified for this subsidy before the government announced that no more projects would be approved under this scheme earlier this year.

Gas for power generation and distributors (who supply the priority natural gas demand) shall be acquired through tender processes, subject to certain maximum prices, to be conducted through the Electronic Gas Market, pursuant to Ministry of Productive Development Resolution No. 12/19, issued on 27 December 2019, and Secretariat of Energy Resolution No. 32/19, issued on 8 February 2019, respectively.

The industrial sector purchases gas from the producers or marketeers directly at freely negotiated prices.

Gas can be marketed by the holders of exploitation concessions, who own the gas extracted, and by marketers, who act as intermediates, by purchasing and selling gas produced by someone else, or by selling gas on behalf of the producer. Producers can be marketers in respect of gas produced by someone else. The exploitation concessionaires’ right to own and sell the gas produced by them is set forth in the Hydrocarbons Law. Marketing is governed, together with transportation and distribution, by Law 24,076, although marketing is not considered a public utility service. Marketers need to register with the Marketers Registrar held by the Secretariat of Energy and comply with certain information regime.

As mentioned in 16 above, the purchase of gas for power generation within the wholesale electric market is centralized by CAMMESA and not purchased directly by the generators, pursuant to the Ministry of Productive Development’s resolution No. 12/19.

Residential consumers, commercial retail customers and small industrial consumers purchase the gas, together with the transportation service, from the distributors, which purchase the gas from the producers and marketers. Large industrial consumers must purchase the fluid directly from the producers.

As regards pricing, as mentioned in 16 above, there is a mix of regulated and market prices at which natural gas is sold.

After the primary elections held in August 2019, the result of which clearly showed that President Macri would not be re-elected and that the candidate of a centre-left populist coalition, Mr. Alberto Fernández, joined in the ticket, as vice-president candidate, by former president Cristina Kirchner, would be the new president, the negative impact in the financial market was immediate. The significant devaluation of the peso and subsequent increase of inflation, forced the exiting government to freeze the price of crude oil and fuels for ninety days (decree No. 566/19), to “interpret”, without any solid legal grounds, Ministry of Energy Resolution No. 46/17 (which enacted the subsidies scheme which boosted investment in large shale gas projects in Vaca Muerta, such as the extraordinarily successful shale gas block Fortín de Piedra), so to significantly reduce the amount of subsidies that the companies whose investment plans had been approved legitimately expected to collect, and reinstate export duties for all goods and services, including oil, gas.

Despite the announcements made during the elections campaign and after taking office in December, 2019, mentioning that the development of the country’s hydrocarbon resources, especially Vaca Muerta, would be a key aspect of their economic plan and that they had the intention to boost investment by immediately passing one or more laws that would include benefits and incentives for the sector, the new administration did nothing in this respect so far. First, it was decided to move the Secretariat of Energy from the Ministry of Economy to the Ministry of Productive Development and then, due to internal disputes, the appointment of key officials, like the Secretary of Energy, under-secretaries and directors suffered several delays. When, finally, a Secretary was appointed – Mr. Lanziani – it did not take long to realise that he lacked the necessary political support to appoint other officials within the Secretariat or to implement any energy policies. This situation resulted in Mr. Lanziani’s resignation, the decision to move the Secretariat of Energy back to the Ministry of Economy (Decree No. 706/20 of 28 August 2020) and to appoint a new Secretary, Mr. Darío Martínez (Decree No. 765/20 of 25 September 2020).

Until the appointment of Mr. Martínez, the only actual and effective measure adopted by the government in relation to the oil and gas industry, was the issuance of Decree No. 488/20, which included a much criticised mandatory fixed reference price to be applied in all domestic crude oil sales during a certain period, together with a positive change in relation to duties applicable to exports of hydrocarbons, replacing the previous fixed 8% rate by a mobile rates system pursuant to which the applicable rate will be 0% if the international reference price (Brent) does not exceed US$ 45, and will be determined by certain formula set forth in the decree when such international reference price is higher than US$ 45 but not higher than US$ 60. If the international reference price is US$ 60 or more, the rate shall be 8%.

Although he has been in office for a short time, Mr. Martínez seems to have a stronger political support than his predecessor had, as well as a more proactive attitude. So far, after several months of delays, the President, together with the Secretary, has formally announced the enactment of a new incentives plan for natural gas producers. This new scheme will aim at keeping certain injection level, with the objective of mitigating the effects of the reduction of exploration and production investment during 2020 (due to the crash of international prices and the pandemic), and reducing, as much as possible, the need to import LNG and gas from Bolivia in the next cold seasons. Under this new gas scheme, that will contemplate a three-year initial term with a one-year extension, producers will be able to submit bids for the supply of gas to the domestic market, subject to a maximum price of approximately US$ 3.40/MMBtu. The portion of the price that is not passed-though to the consumers will be paid by the federal government. The companies submitting bids shall commit to maintain the average injection of gas to the system registered during May and June of 2020. The companies which bids are awarded the supply will also be entitled to certain firm export quotas to be used during the warm season. As of the date on which this report is being written, the scheme has not been enacted yet.

Before the crash of international prices during the first quarter this year and the Covid-19 pandemic that hit the country soon thereafter, one of the main challenges faced by the industry in Argentina was the lack of transport and storage infrastructure to evacuate the increasing oil and, especially, gas production from the Vaca Muerta shale play. In the case of gas, such infrastructure includes, not only the construction of new pipelines (or the enhancement of the transportation capacity of the existing pipelines), but also the construction of a liquefaction facility, or the assembly of several smaller modular liquefaction plants. The industry and the government estimated that the lack of such infrastructure would pose a limitation on the development of world class prospects like the Fortín de Piedra block and other promising shale gas fields in Vaca Muerta in the near future. Closely related to this, the other challenge identified by the industry is being able to produce gas at wellhead at a competitive cost, which will require to improve efficiency and reduce production costs, in a scenario of low international prices.

In turn, these challenges are linked with other challenges, like the need to have and show a strong commitment to sustain consistent policies aimed at incentivising investment (tax benefits, a foreign exchange regime that allows the free availability of all or a substantial portion of exports proceeds and the payment of dividends abroad), avoiding inconsistencies and contradictions like the abovementioned reinterpretation of Resolution No. 47/16, the establishment of unrealistic fixed domestic prices (Decree 488/20) and, generally, avoiding excessive intervention and control (either by the issuance of formal regulations or de facto) as it happened during the period between 2002 and 2012.

In addition to the abovementioned, the irruption of the Covid-19 pandemic created new urgent challenges. The pandemic broke into the country in March this year, with a massive impact on the economy in general and on the oil and gas industry in particular. Decree No. 297/20, issued on 20 March 2020, imposed a mandatory lockdown that, although gradually softened in many aspects, remained in force for several months. The demand for fuels in April dropped between 80% and 50%, depending on the type of fuel, such demand slowly recovering since May, which resulted in the temporary shutting-in of fields, temporary shutting-down of refineries and production being kept at minimum levels (no fracking stages were reported during April). This also resulted in the oil and gas producing provinces suffering a dramatic loss of income, as hydrocarbon royalties pay for a substantial portion of their budgets.

In this scenario the national Executive issued decree No. 488 on 19 May 2020, which (i) established, until December 31, 2020 or until the price of Brent oil exceeds US$ 60/bbl, that the price of all domestic sales shall be calculated on a fixed Medanito crude oil reference price of US$ 45/bbl and the prices so calculated shall be used for the calculation of the royalty payable to the provinces; and (ii) replaced the existing fixed-rate export duty applicable to hydrocarbons exports by a mobile rates system as described in 18 above. During the time in which the scheme was in force (until the price of Brent reached US$ 60/bbl), the fixed domestic reference price has proved to be a problem rather than a solution for producers, as the prices they could actually charge to refineries were significantly lower than the prices they should have charged pursuant to the decree. This resulted in several disputes with the provinces in connection with the base price to be considered for the calculation of royalties; this is, the actual price received by the producers, as set forth in the Hydrocarbons Law and acknowledged by profuse National Supreme Court’s caselaw (position sustained by the producers) or the fictional fixed price provided for in the decree (position sustained by the provinces). On the other hand, the change made to the export duty rates has helped producers to increase exports and gradually resume certain activity level as international demand and prices began to recover.

Argentina has ratified the United Nations Framework Convention on Climate Change (UNFCCC), by Law No. 24,295; the Kyoto Protocol, by Law No. 25,438; and the Paris Agreement, by Law No. 27,020.

Certain actions have been taken in Argentina in line with the objectives of such conventions (although they are not a specific enforcement thereof), including:

(i) the enactment of 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 (Laws No. 26,093 and No. 26,334, and other supplementary regulations); and

(ii) the modification of technical specifications of fossil fuels, including a reduction in the maximum sulphur content in fuel oil and diesel oil used in power generation, with the purpose of reducing the emissions of substances causing acid rain and particulate matter (Resolution SRH No. 5/16).

Also, although not related directly to the oil and gas sector, Law No. 27,791, passed in September 2015, established that, by 31 December 2025, the energy produced from renewable sources should contribute 20% of the country’s total consumption.