The Argentine Gas and Oil Market

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The Argentine Energy Matrix

Natural gas and oil constitute the main energy sources in the national primary energy matrix. The following chart illustrates their shares as of December 31, 2017, as there is no available information for the year 2018 as of the date of 2018 Annual Report’s release:

Type of Energy Million ton of oil equivalent %
Natural Gas 43.3 54.0%
Oil 25.0 31.2%
Hydro 3.5 4.3%
Nuclear 1.8 2.2%
Coal 1.1 1.3%
Renewables 0.2 0.2%
Others 5.4 6.8%
Total 80.3 100%

Source: The Government Secretariat of Energy (‘SGE’).

 

Natural Gas

During 2018, the total gross natural gas production amounted to 129 million cubic meters (‘m3‘) per day, which represents a 5% increase compared to the volumes produced in 2017. This is mainly due to the continuous growth of production in the Neuquina Basin (+6 million m3 per day) and, to a lesser extent, in the Austral Basin (+2 million m3 per day), with an increase in contributions associated with the development of unconventional gas reserves, which was partially offset by the decline in the Golfo San Jorge and Noroeste basins.

As regards natural gas imports by the Argentine Government, the supply from Bolivia reached an average of 16.3 million m3 per day in 2018, a figure 10% lower than the volume recorded in 2017. In this same sense, imports of seaborne Liquefied natural gas (‘LNG’) later injected in the national natural gas transportation system at the Bahía Blanca and Escobar ports, in the Province of Buenos Aires, recorded an average contribution of 10 million m3 per day in the year 2018, 24% lower than the volume recorded in 2017. Furthermore, imports of LNG regasified in Chile totaled 0.6 million m3 per day, a volume slightly lower than that recorded in 2017, which amounted to 0.8 million m3 per day.

Based on the last annual information published by the SGE, as of December 31, 2017 total natural gas reserves and resources within the country reached 1,052,011 million m3, of which 34% are proven reserves. Furthermore, 51% of the total reserves and resources were unconventional. Compared with the same information as of December 31, 2016, total reserves and resources have recorded a 23% increase. Furthermore, resources increased by 53%, totaling 359,924 million m3.

 

Oil

In 2018, total oil production amounted to 78 thousand m3 per day, a volume slightly higher than that recorded in 2017 (76 thousand m3 per day), thus reversing the downward trend in oil production recorded in Argentina over the last sixteen years.

Based on the last annual information published by the SGE on oil imports, during 2018 1.2 thousand m3 per day were imported, a volume 65% lower than that recorded in 2017. This volume represented only 2% of the total domestic production during 2018. On the other hand, in 2018 oil exports amounted to 9.3 thousand m3 per day, a volume 105% higher than in 2017. This volume represented 12% of the total domestic production during 2018.

As of December 31, 2017, total oil reserves and resources within the country totaled 687,319 thousand m3, of which 47% were proven reserves. Furthermore, 18% of the total reserves and resources were unconventional. Compared with the same information as of December 31, 2016, total reserves and resources have recorded a slight 3% decrease. Furthermore, resources increased by 4%, totaling 169,775 thousand m3.

Amendment to the Argentine Hydrocarbons Law

On October 29, 2014, the National Congress enacted Law No. 27,007 amending Hydrocarbons Law No. 17,319. This Law incorporates new drilling techniques available in the industry, as well as changes mainly related to terms and extensions of exploration permits and exploitation concessions, levies and royalty rates, the incorporation of concepts for the continental shelf and off-shore exploration and exploitation of unconventional hydrocarbons, and a promotion regime pursuant to Executive Order No. 929/13, among other key factors for the industry. The main changes introduced by Law No. 27,007 are detailed below:

 

Unconventional Hydrocarbons Exploitation

The Law conferred a legal status to the concept of ‘Hydrocarbon Unconventional Exploitation Concession’ created by Executive Order No. 929/13. The term hydrocarbon unconventional exploitation is defined as the extraction of liquid and/or gaseous hydrocarbons by unconventional stimulation techniques applied in reservoirs situated in geological formations of schist rock or slate (shale gas or shale oil), tight sandstone (tight sands, tight gas, tight oil), coal bed methane and/or deposits characterized, in general, by the presence of low permeability rocks.

Holders of exploration permits and/or hydrocarbon exploitation concessions will be entitled to request a hydrocarbon unconventional exploitation concession to the enforcement authority pursuant to the following terms:

  • The exploitation concessionaire may request, within its block, the subdivision of the existing block into new hydrocarbon unconventional exploitation blocks and the granting of a hydrocarbon unconventional exploitation concession. Such request will be based on the development of a pilot plan aiming at the commercial exploitation of the discovered reservoir pursuant to acceptable technical and economic criteria.
  • Holders of a hydrocarbon unconventional exploitation concession also being holders of a preexisting and adjacent exploitation concession may request the unification of both blocks as a single hydrocarbon unconventional exploitation concession provided they duly demonstrate the geological continuity of these blocks. Such request should be based on the development of a pilot plan.

 

Terms for Exploitation Concessions and Permits

The terms for the exploration permits will be established in each tender issued by the enforcement authority according to the exploration’s purpose (conventional or unconventional) and based on the following criteria:

  • Conventional exploration: the basic term is divided into two periods of up to three years each, plus an optional extension of up to five years. In this way, the maximum extension for exploration permits is reduced from fourteen to eleven years;
  • Unconventional exploration: the basic term is divided into two periods of four years each, plus an optional extension of up to five years, that is, up to a maximum of 13 years; and
  • Exploration in the continental shelf and the territorial sea: the basic term is divided into two periods of three years each, plus an optional extension of one year each.

Upon the expiration of the basic term’s first period, the exploration permit holder will decide whether to continue exploring the block or to transfer it back in whole to the Government. The whole originally-granted block may be kept provided the obligations arising from the permit have been properly met. Upon the expiration of the basic term, the holder of the exploration permit will revert the whole block, unless it exercises its right to use the extension period, in which case the reversion will be limited to 50% of the remaining block.

Exploitation concessions will be granted for the following terms, which will be computed as from the granting resolution’s date:

  • Conventional exploitation concession: 25 years;
  • Unconventional exploitation concession: 35 years; and
  • Continental shelf and off-shore exploitation concession: 30 years.

Furthermore, the holder of an exploitation concession may, with a minimum one-year notice before the expiration of the concession, request the granting of indefinite extensions, for a 10-year term each, provided it has properly met its obligations as exploitation concessionaire, is actually producing hydrocarbons in the blocks in question, and files an investment plan consistent with the development of the concession.

The ban on simultaneously holding more than five exploration permits and/or exploitation concessions (whether directly or indirectly) has been lifted.

 

Concessions Extension

Law No. 27,007 grants the provinces having already started the concession extension process a 90-day term to finish it based on the conditions established for each of them. All subsequent extensions will be governed by the Argentine Hydrocarbons Law.

 

Awarding of Blocks

Law No. 27,007 proposes the drafting of a standard bid form that will be jointly made by the Former Secretariat of Energy (‘SE’) and the provincial authorities, to which all tenders launched by law enforcement authorities should adjust, and introduces a specific criterion for the awarding of permits and concessions by incorporating the specific parameter of ‘greater investment or exploration activity’ as tie-breaker, at the National Executive Branch (‘PEN’ or Poder Ejecutivo Nacional) or the Provincial Executive Branch’s duly supported discretion, as applicable.

 

Levy and Royalties

The amended Argentine Hydrocarbons Law updated the values related to the exploration and exploitation levy established by Executive Order No. 1,454/07; such values may, in turn, be generally updated by the Executive Branch based on variations in the domestic market’s crude oil price. The updated values for each levy and royalty are detailed below.

 

Exploration Levy

The holder of the exploration permit will pay the levy on an annual basis, in advance, for each square kilometer or its fraction based on the following scale:

  • First period: AR$250 per square kilometer (‘km2‘) or fraction;
  • Second period: AR$1,000 per km2 or fraction; and
  • Extension: during the first year of the extension; AR$17,500 per km2 or fraction, with a 25% annual cumulative increase.

In this case, offsetting mechanisms will remain in place: the amount that the exploration permit holder should pay for the second period of the basic term and for the extension period may be readjusted by offsetting it with exploration investments actually made within the block, until reaching a minimum levy equivalent to 10% of the applicable levy according to the period per km2, which will be payable in all cases.

 

Exploitation Levy

The holder of the exploitation permit will pay a levy which will consist of an annual advance payment of AR$4,500 per km2 or its fraction.

 

Royalties

Royalties are defined as the only revenue the jurisdictions holding title to the hydrocarbons will collect, in their capacity as grantors, from the production of hydrocarbons.

The percentage the exploitation concessionaire should pay on a monthly basis to the grantor as royalty remains at 12% of the proceeds derived from liquid hydrocarbons production extracted at wellhead. The production of natural gas will bear a like percentage of the value of extracted and actually used volumes, and will be payable on a monthly basis.

Cash payment of the royalty will be made based on the value of crude oil at wellhead less freight costs up to the base location for the definition of its commercial value. Payment in kind of this royalty will only apply when the concessionaire is assured a reasonably permanent reception. The possibility to reduce the royalty up to 5% taking into consideration productivity, conditions and wells location remains in place.

In case of extension, additional royalties for up to 3% of the royalties applicable upon the first extension and up to a total maximum of 18% of royalties for the following extensions will be payable.

For the conduction of hydrocarbon conventional exploitation complementary activities, as from the expiration of the granted concession and within the hydrocarbons unconventional exploitation concession, the enforcement authority may fix additional royalties of up to 3% above the current royalties, up to a maximum 18%, as applicable.

The PEN or the Provincial Executive Branch, as applicable, acting in its capacity as granting authority, may reduce by up to 25% the amount corresponding to royalties applicable to the production of hydrocarbons during a term of 10 years after the conclusion of the pilot project in favor of companies requesting a hydrocarbon unconventional exploitation concession within a term of 36 months as from Law No. 27,007’s effective date.

Finally, with the Hydrocarbon Investments Committee’s prior approval, royalties may be reduced to 50% for tertiary production projects, extra-heavy oil and offshore products in view of their productivity, location and other unfavorable economic and technical characteristics.

 

Extension Bond

For exploitation concession extensions, Law No. 27,007 empowers the enforcement authority to establish the payment of an extension bond, the maximum amount of which will result from multiplying the remaining proven reserves at the expiration of the concession by 2% of the average basin price applicable to the specific hydrocarbon during a term of 2 years before the granting of the extension.

 

Exploitation Bond

The enforcement authority may establish the payment of an exploitation bond, the maximum amount of which will result from multiplying the remaining proven reserves associated with the exploitation of conventional hydrocarbons at the expiration of the granted concession by 2% of the average basin price applicable to the specific hydrocarbons for the two years prior to the granting of the hydrocarbon unconventional exploitation concession.

 

Transportation Concessions

Transportation concessions (which had so far been granted for 35 years) will be granted for the same term than that granted for the originating exploitation concession, with the possibility of receiving subsequent extensions for up to 10 years each. Thus, transportation concessions originating in a conventional exploitation concession will have a basic 25-year term, whereas those originating in an unconventional exploitation concession will have a basic 35-year term, each plus any granted extension term. After the expiration of these terms, title to the facilities will be transferred back to the Federal or Provincial Government, as applicable, by operation of law and without any charges or encumbrances whatsoever.

 

Uniform Legislation

Law No. 27,007 provides for two types of non-binding commitments between the Federal Government and the provinces regarding tax and environmental issues:

  • Environmental Legislation: It provides that the Federal Government and the provinces will seek to establish a uniform environmental legislation primarily aiming to apply the best environmental management practices to hydrocarbon exploration, exploitation and/or transportation with the purpose of furthering the development of the activity while properly protecting the environment.
  • Tax System: It provides that the Federal Government and the provinces will seek to adopt a uniform fiscal treatment encouraging the development of hydrocarbon activities in their corresponding territories in adherence with the following guidelines:
    • The gross receipts tax rate applicable to the extraction of hydrocarbons will not exceed 3%;
    • The freezing of the current stamp tax rate and the commitment not to charge with it any financial contracts executed in order to structure investment projects, guarantee and/or warrant investments; and
    • The commitment by the provinces and its municipalities not to impose new taxes —or increase the existing ones— on permit and concession holders, except for service compensation rates, improvement contributions and general tax increases.

 

Restrictions on the Reservation of Blocks to National or Provincial Government-Controlled Companies

The amendment to the Argentine Hydrocarbons Law restricts the Federal Government and the provinces from reserving new blocks in the future in favor of public or mixed companies or entities, irrespective of their legal form. Thus, contracts entered into by provincial companies for the exploration and development of reserved blocks before this amendment are safeguarded.

Regarding blocks that have already been reserved in favor of public companies and that have not yet been awarded under joint venture agreements with third parties, associative schemes may be used, in which case the participation of such companies during the development stage will be proportional to their investments. In this way, the ‘carry’ system during the blocks’ development or exploitation stage has been done away with. Such system has not been prohibited for the exploration stage.

 

Conventional and Unconventional Hydrocarbon Investment Promotion Regime

On July 11, 2013, the PEN issued Executive Order No. 929/13, which created the Investment Promotion Regime for the Exploitation of Hydrocarbons —both conventional and unconventional— with the purpose of encouraging investments destined to the exploitation of hydrocarbons, and introduced the concept of hydrocarbons unconventional exploitation concession.

Law No. 27,007 extends the benefits of the Promotion Regime to hydrocarbon projects involving a minimum of US$250 million direct investment denominated in foreign currency, assessed at the time the hydrocarbon exploitation investment project is presented, to be invested during its first 3 years. Before the amendment, the Promotion Regime benefits reached investment projects denominated in foreign currency for a minimum US$1,000 million amount during a term of 5 years.

Holders of exploration permits and/or hydrocarbons exploitation concessions, and/or third parties associated with such holders and registered with the National Registry of Hydrocarbon Investments submitting this kind of projects will enjoy the following rights as from the third year of their respective projects’ execution:

  • The right to freely sell abroad 20% and 60% of the liquid and gaseous hydrocarbon production in the case of conventional and unconventional exploitation projects and in offshore projects, respectively, with a 0% export duty, if applicable; and
  • The free availability of 100% of the foreign currency derived from the exportation of these hydrocarbons, provided the applicable projects have involved a minimum of US$250 million entry of foreign currency into the Argentine financial market.

During periods in which the national production of hydrocarbons is insufficient to meet domestic supply needs pursuant to Section 6 of the Argentine Hydrocarbons Law, the subjects covered by the Promotion Regime will have, as from the third year following the execution of their respective investment projects, the right to obtain a price not lower than the reference export price (without computing the incidence of any applicable export duties) from the exportable liquid and gaseous hydrocarbon percentage produced under such projects.

Pursuant to these investment projects, Law No. 27,007 provides for two contributions payable to the producing provinces where the investment project is conducted:

  • The first one, payable by the project holder, for an amount equivalent to 2.5% of the investment amount undertaken to be committed to corporate social responsibility projects; and
  • The second contribution, payable by the Federal Government, which amount will be determined by the Hydrocarbon Investments Committee based on the size and scope of the investment project, and which will be destined to infrastructure projects.
Regulations Specifically Applicable to the Gas Market
Encouragement Programs for the Increase in Domestic Natural Gas Production
Gas Plus
In a context of regulated prices and without market intervention in the commercialization of gas, the main appeal of this program for gas producers, created in 2008, was the free availability and commercialization of the extracted gas. In order to qualify, the producer had to submit an investment project in new gas blocks, in blocks which had not been in production since 2004, or in blocks with complex geological characteristics of compact sands or low permeability. Additionally, except for new entities, companies had to be up-to-date with the production quota fixed pursuant to the Natural Gas Producers’ Agreement.

In May 2016, Resolution No. 74/16 of the former Ministry of Energy and Mining (‘MEyM’) created the ‘New Natural Gas Projects Promotion Program’, which provided that no new projects may be submitted under the Gas Plus program, although approved projects would remain effective under the same conditions.

In September 2018, Gas Plus agreements timely entered into by Pampa expired.
 
Plan Gas I
On February 14, 2013, Resolution No. 1/13 was published in the Public Gazette (‘BO’ or Boletín Oficial) establishing the Plan Gas I (Natural Gas Surplus Injection Promotion Program), which aims to evaluate and approve projects furthering the national self-supply of hydrocarbons through a gas production increase and its injection into the domestic market, as well as to generate higher levels of activity, investment and employment in the sector.

Before June 30, 2013, any company registered with the National Registry of Hydrocarbon Investments created by Executive Order No. 1277/12 could submit its projects before the Hydrocarbon Investments Committee. The Federal Government had undertaken to pay a monthly compensation resulting from:

  • The difference between the Surplus Injection price (US$7.5/million BTUs (‘MMBTU’)) and the price actually collected from the sale of the Surplus Injection; plus
  • The difference between the Base Price and the price actually collected from the sale of the Adjusted Base Injection.

These projects would be in force for a maximum term of 5 years as from January 1, 2013, with the possibility for an extension.

On April 26, 2013, Hydrocarbon Investments Committee’s Resolution No. 3/13 was published in the BO, which regulated Plan Gas I and provided that companies interested in participating in this program should submit monthly affidavits to the Hydrocarbon Investments Committee containing specifically-detailed documentation on injection, price, contracts, etc., so that they may, after meeting the methodology and terms specified therein, obtain the applicable compensation. Furthermore, the resolution expressly prohibited natural gas purchase and sale transactions between producers, and provided for special considerations regarding new high-risk projects, investments control, the evolution of reserves, and Plan Gas I’s audit mechanism.

On July 11, 2013, pursuant to Provision No. 15/13 of the Hydrocarbon Investments Committee, Petrolera Pampa S.A. (‘PEPASA’) was registered with the National Registry of Hydrocarbon Investments. PEPASA submitted several projects so that the Hydrocarbon Investments Committee should evaluate its inclusion under Plan Gas I. On August 7, 2013, pursuant to Resolution No. 27/13, the Hydrocarbon Investments Committee approved the submitted projects for an increase in the total natural gas injection, with retroactive effects as of March 1, 2013.

On July 15, 2015, the Hydrocarbon Investments Committee published Resolution No. 123/15 creating the Rules applicable to acquisitions, sales and assignments of blocks, rights and interests under Plan Gas I. These rules provided that companies acquiring, selling or assigning blocks, rights or interests should submit the applicable presentation within a term of 10 business days after the transaction is made. PEPASA filed the applicable presentation for operations conducted in the Rincón del Mangrullo block.
 
Plan Gas II
In November 2013, the Hydrocarbon Investments Committee issued Resolution No. 60/13 establishing Plan Gas II (Natural Gas Injection Promotion Program for Companies with Reduced Injection). Producers could submit projects to increase natural gas production levels until March 31, 2014. This program was targeted at companies with no previous production or with a maximum injection limit of 3.5 million cubic meters (‘m3’) per day, and provided for price incentives in the case of production increases, and penalties involving Liquefied Natural Gas (‘LNG’) imports in the case of non-compliance with committed volumes. Furthermore, beneficiary companies covered by Plan Gas I and meeting the applicable conditions could request the termination of their participation in that program and their incorporation into Plan Gas II.

In March 2014, Resolution No. 60/13 was amended by Resolution No. 22/14 issued by the Hydrocarbon Investments Committee, whereby the deadline for submission was extended until April 30, 2014, and the previous maximum injection limit was increased to 4.0 million m3/day.

In August 2014, the Ministry of Economy (‘MECON’), through Resolution No. 139/14, introduced new changes to Resolution No. 60/13 issued by the Hydrocarbon Investments Committee, including, among others, the elimination of the previous maximum injection limit and the fixing of two annual registration periods. Former Petrobras Argentina filed an application to be included under Plan Gas II and was registered with this program on January 30, 2015 pursuant to Resolution No. 13/15 issued by the Hydrocarbon Investments Committee. The participation of Pampa’s areas included under Plan Gas II is effective until June 30, 2018.

In furtherance of Hydrocarbon Investments Committee’s Resolution No. 123/15, Pampa modified its registration following the assignment, in March 2015, of 100% of its blocks in the Austral Basin (Santa Cruz I and II) to YPF and, in October 2016, 33.33% of its interests in Río Neuquén and 80% of its interests in Aguada de la Arena to Yacimientos Petrolíferos Fiscales S.A. (‘YPF’), as well as the assignment of 33.60% of its interests in Río Neuquén to Petrobras Operaciones S.A.

Furthermore, Resolution No. 185/15 created the ‘Program for the Promotion of Natural Gas Injection for Companies with No Injection’, the compensation mechanism of which is similar to Plan Gas I and Plan Gas II’s.

On January 4, 2016, Executive Order No. 272/15 was published, which dissolved the Hydrocarbon Investments Committee created pursuant to Executive Order No. 1277/12, and provided that its powers would be vested in the MEyM.

On May 18, 2016, the MEyM passed the above-mentioned Resolution No. 74/16 creating the New Natural Gas Projects Promotion Program. This Resolution superseded the program created by Hydrocarbon Investments Committee’s Resolution No. 185/15. This new incentive program sought to attract new projects by companies not covered by either Plan Gas I or Plan Gas II, established specific requirements, and was effective until December 31, 2018.
 
Unconventional Plan Gas
On March 6, 2017, MEyM Resolution No. 46/2017 was published in the BO creating the Encouragement Program to further investments for the production of natural gas from unconventional reservoirs in the Neuquina Basin effective from its publication to December 31, 2021.

This program provided for a compensation mechanism for each beneficiary company of the unconventional gas volume —either tight or shale— produced in the Neuquina Basin, which was calculated based on a minimum guaranteed price and the total weighted-average sale price of gas by each company to the domestic market, including both conventional and unconventional gas. The minimum price was fixed at US$7.5/MBTU for calendar year 2018, and would be later decreased by US$0.5/MBTU per year until reaching US$6.0/MBTU for calendar year 2021.

This program provides for a more agile payment method, with the initial disbursement of a provisional payment based on 85% of the theoretical compensation resulting from projections, the difference being later adjusted, either positively or negatively, based on actual production. Additionally, compensations resulting from the Unconventional Plan Gas for each concession will be paid as follows: 88% to companies and 12% to the province where the concession under the Unconventional Plan Gas is located.

Later, on November 2, 2017, MEyM Resolution No. 419/2017 was published in the BO, which amended the terms and conditions provided for by MEyM Resolution No. 46/2017. The new Resolution classifies projects into pilot and developing, the latter having an initial production, that is, a monthly average unconventional gas production equal to or higher than 500,000 m3 per day between July 2016 and June 2017.

Pilot projects applying for the incentive may obtain the guaranteed minimum price for their whole unconventional production provided they reach an annual average production equal to or higher than 500,000 m3 per day during a twelve-month period by December 31, 2019. Developing projects may only apply for the incentive for the incremental portion on top of the defined initial production. The reference price for the incentive would be calculated using the domestic market’s weighted average reported by the MEyM’s Subsecretariat of Hydrocarbon Resources (‘SRH’). Furthermore, permanence in the program would be conditional upon the blocks meeting the investment plan timely informed to the provincial enforcement authority; otherwise, collected amounts, adjusted by the Argentine National Bank (‘BNA’ or Banco de la Nación Argentina)’s interest rate, should be returned.

On the other hand, on November 17, 2017 MEyM Resolution No. 447/17 was published in the BO, which extends the application of the Unconventional Plan Gas to the Austral Basin. Additionally, on January 20, 2018, MEyM Resolution No. 12/18 was issued, which introduced the applicable amendments to the Unconventional Plan Gas so as to apply the incentives provided therein to adjacent concessions operated on a unified basis and meeting all other applicable conditions. Since companies interested in participating in the Unconventional Plan Gas had suffered certain delays in the proceedings for the granting and approval of their specific investment plans, they requested an adjustment in the payment date of the first compensation under the Unconventional Plan Gas, and, correspondingly, the performance of the applicable reviews associated with the initial provisional payment.

Pampa had requested before the Government Secretariat of Energy (‘SGE’) for the inclusion under this program of its projects in the Río Neuquén, El Mangrullo and Sierra Chata blocks, which had been previously approved by the Provincial enforcement authority. However, on January 30, 2019, in a meeting called by the SGE with the participation of gas producers affected by the Unconventional Plan Gas, including the Company, it was informed that no new projects will be approved under the Unconventional Plan Gas, and that the SGE will evaluate a new encouragement scheme for the production of unconventional gas during the winter season.

Natural Gas for the Residential and Compressed Natural Gas (‘CNG’) Segment
Priority Demand and Emergency Executive Committee (‘CEE’ or Comité Ejecutivo de Emergencia)
In 2007, the Argentine Government and producers signed a Natural Gas Producers’ Agreement, the main goals of which were to secure supply of the domestic demand for gas and the gradual recovery in prices through all market segments. The afore-mentioned agreement was approved by Resolution No. 599/07 of the former Secretariat of Energy (‘SE’), being the residential supply commitment the last expiration in December 2011.

In October 2010, through Resolution I-1410 issued by the National Gas Regulatory Entity (‘ENARGAS’ or Ente Nacional Regulador del Gas), the natural gas dispatch method was modified, placing a priority on the supply of the residential and CNG segments’ demand, with volumes exceeding those stipulated under SE Resolution No. 599/07. In December 2011, the Argentine Government, through SE Resolution No. 172/11, temporarily extended the conditions of the Producers’ Agreements on a unilateral basis, and thus allowed ENARGAS to continue using gas producers’ shares stipulated in such agreement.

In June 2016, MEyM Resolution No. 89/16 was published in the BO, which established the criteria for the normalization of natural gas purchase agreements within the Transportation System Entry Point (‘PIST’) by distribution service providers in order to meet the Priority Demand (set of residential users, hospitals, schools, healthcare centers and other essential services). Additionally, criteria were established to guarantee the meeting of the Priority Demand through the CEE in case of operational emergencies which may affect the normal supply.

Finally, in June 2017 ENARGAS Resolution No. 4502/17 was issued, which approved the procedure for dispatch administration in the CEE. In case the CEE did not reach an agreement, ENARGAS would define the supply taking into consideration each producer’s available quantities, deducting the amounts previously contracted to meet the Priority Demand, with a progressive allocation until matching the proportional quota of each producer/importer in the Priority Demand.
 
New Natural Gas Prices within the PIST
In early January, 2018, the extension period set forth by Law No. 27,200 to the public emergency declared in 2002 terminated and, therefore, Law No. 24,076 was reinstated, which provides that the price of natural gas supply agreements should be determined by the free interaction of supply and demand. As a result, in November 2017 and supported by the MEyM, natural gas distributors executed an agreement with the country’s main natural gas producers, including Pampa, effective for a year as from January 1, 2018. Prices were differentiated based on the source basin, the user category, and whether the tariff was full or differential, with periodic increases, and ranged from US$1/MBTU to US$6.5/MBTU.

However, on account of the significant devaluation of the AR$ and the impossibility by distributors to pass this new exchange rate on to final users’ tariff schemes, in early October, 2018, this agreement was rendered ineffective and, consequently, prices began to be agreed with distributors in the spot market on a daily basis.

Furthermore, ENARGAS Resolution No. 280-289 and 292/2018 were issued, which established, effective for a six-month period beginning on October 1, 2018, new natural gas final tariffs for residential, P General Service with full service and CNG users, considering a price of natural gas as a raw material ranging between US$1.74/MBTU and US$3.98/MBTU, including the differential tariff(1).

On the other hand, on November 15, 2018 Executive Order No. 1053/2018 of the National Executive Branch (‘PEN’ or Poder Ejecutivo Nacional) was issued, which established, on an exceptional basis, that the Federal Government would bear the exchange difference between the price of gas purchased by gas distributors and that recognized in the gas distributors’ final tariffs for the April 2018 – March 2019 period, in 30 monthly and consecutive installments payable as from October 1, 2019.

Finally, on February 12, 2019, with the publication in the BO of ENARGAS Resolution No. 72/19, the methodology for passing the gas price on to tariffs and the general procedure for calculating accumulated daily exchange differences entered into effect. Among other aspects, this methodology contemplates the recognition of prices stipulated in the agreements entered into between distributors and producers and the definition of the exchange rate to be used. Specifically, it provides that the exchange rate to be considered between producers and distributors should be BNA’s average currency exchange rate for the first 15 days of the month immediately preceding the beginning of each seasonal period or, if lower, the exchange rates stipulated in the agreements.
Note: (1)Tariff schemes for final users are denominated in AR$, and these resolutions contemplate a AR$37.69/US$ exchange rate, BNA’s closing rate on October 3, 2018.
 
Public Tender for Gas Supply on a Firm Basis
SGE Resolution No. 32/19, published in the BO on February 11, 2019, approved the mechanisms for the single-price public tender to supply gas on a firm basis to gas distributors from producers and former Energía Argentina S.A. (‘IEASA’ or former ENARSA). It also defined ToP (take or pay) commitments for the purchaser and DoP (deliver or pay) commitments for the seller for up to 70% of the maximum daily volume for a term of 12 months, with seasonality, effective as from April 2019.

From the southern and Neuquina basins, 14.4 million m3 per day were assigned for the summer, and 36.1 million m3 per day for the winter, at a weighted average price by awarded bids of US$4.62/MBTU. Out of these volumes, 83% corresponded to the Neuquina Basin at a weighted average price of US$4.61/MBTU. Pampa tendered and was awarded this auction.

Furthermore, from the Noroeste Basin, 3.8 million m3 per day were assigned for the summer and 9.4 million m3 per day for the winter, at a weighted average price of US$4.35/MBTU.

Natural Gas for Electric Power Generation
On April 13, 2016, MEyM Resolution No. 41/16 established new natural gas prices for the power plants’ segment, which reached an average price of US$5.20/MBTU, the highest price (US$5.53/MBTU) being for the Neuquina Basin.

However, on August 1, 2018, Resolution No. 46/2018 of the former Ministry of Energy (‘MinEn’) was published in the BO, which set maximum prices within the PIST for natural gas, based on the source basin, effective as from the publication of such Resolution, with a weighted average of US$4.20/MBTU, and a price of US$4.42/MBTU for the Neuquina Basin.

On September 6, 2018, Argentine Wholesale Electricity Market Clearing Company’s (‘CAMMESA’ or Compañía Administradora del Mercado Eléctrico Mayorista S.A.)’s auction for the September – December 2018 period took place, and price indications were received for a total gas volume of 143 million m3 per day on an interruptible basis, at a weighted average PIST price of US$3.8/MBTU. Furthermore, on December 27, 2018, under another CAMMESA’s auction conducted for the year 2019, price indications were received for a total gas volume of 222 million m3 per day on an interruptible basis, at seasonal PIST prices with a maximum price of US$5.2/MBTU and a minimum price of US$3.2/MBTU for the June – August 2019 period, and with a maximum price of US$3.7/MBTU and a minimum price of US$2.2/MBTU for the rest of the year. Pampa participated in both auctions.

In the last CAMMESA’s auction, maximum PIST seasonal reference prices were considered based on the source basin, pursuant to SGE Note No. 66680075/2018 issued on December 19, 2018 and effective as from January 2019. In the case of the Neuquina Basin, for the June – August 2019 period the price was set at US$4.95/MBTU, and for the rest of the year at US$3.70/MBTU.

On the other hand, seeking that the Wholesale Electricity Market (‘WEM’) should bear the costs of imported gas and, consequently, reflect them in the variable costs the electric dispatch is based on, on October 4, 2018 SGE Resolution No. 25/2018 was issued, which provides that, in case the supplier is IEASA, CAMMESA should adopt the acquisition and commercialization cost, effective as from October 1, 2018.

Natural Gas Export
On August 21 and September 15, 2018, MinEn Resolution No. 104/2018 and SGE Resolution No. 9/2018, respectively, were issued establishing a Procedure for the Authorization of Natural Gas Exports, being the security of supply to the Argentine domestic market a condition in all cases. Furthermore, in the case of projects covered by the Unconventional Plan Gas, exported natural gas may not be eligible for such program.

In December 2018 and January 2019, Pampa was authorized pursuant to SGE Resolution No. 252/2018 and 12/2019 to export natural gas to Chile and Uruguay, on an interruptible basis, from the Río Neuquén and Rincón del Mangrullo blocks.

On the other hand, Executive Orders No. 793 and 865/2018, issued by the PEN on September 3 and 27, 2018, respectively, regulated the application of a duty on exports for all the goods under the Common Mercosur Nomenclature, including natural gas, effective as from September 4, 2018 to December 31, 2020. This duty provides for a AR$4 withholding on each exported US$, with a maximum 12% tax rate.

Regulations Specifically Applicable to the Crude Oil Market

Liquid Hydrocarbons Export Duty
On December 29, 2014, Resolution No. 1077/14 of the Ministry of Economy (‘MECON’) established export duty rates in line with the crude oil’s international price, which was determined based on the reference Brent’s value on the month corresponding to the export minus US$8.0/barrel (‘bbl’). Under this system, if the international price did not exceed US$71, the producer paid export duties for 1% of that value, and if the international price exceeded US$72/bbl, variable withholdings were settled. This system would be in force for a term of 5 years as from its enactment on January 6, 2002. The term was extended for a five-year term pursuant to Law No. 26,217, and later re-extended for a like term pursuant to Law No. 26,732. On January 6, 2017, upon the absence of extension, the provisions regulating this issue (Public Emergency Law No. 25,561/02, as amended and supplemented), the withholdings scheme on the exports of oil and its derivatives terminated and, therefore, all applicable outstanding rights were canceled by the Customs Office.

On the other hand, Executive Orders No. 793 and 865/2018, issued by the National Executive Branch (‘PEN’ or Poder Ejecutivo Nacional) on September 3 and 27, 2018, respectively, regulated the application of a duty on exports for all the goods under the Common Mercosur Nomenclature, including crude oil, effective as from September 4, 2018 to December 31, 2020. This duty provides for a AR$4 withholding on each exported US$, with a maximum 12% tax rate.
 
Agreement for the Transition to International Prices in the Argentine Hydrocarbon Industry
In December 2015, the abolition of official foreign exchange control regulations had a direct impact on crude oil costs for refineries. Therefore, the Federal Government agreed with Argentine producers and refineries on a crude oil price for 2016 leading to a gradual convergence of the price of the crude oil barrel traded in Argentina towards the international price.

Later, on January 11, 2017, the Federal Government executed the Agreement for the Transition to International Price in the Argentine Hydrocarbon Industry with producers and refineries of crude oil with the same purpose of generating a gradual convergence of the price of the crude oil barrel traded in Argentina towards the international price.

On March 21, 2017, on account of the lower international prices and seeking to sustain the domestic activity, Executive Order No. 192/2017 provided for the regulation of imports of crude oil and certain derivatives until domestic prices converge towards international prices.

Finally, on September 22, 2017, through Note No. 21505927/17, the former Ministry of Energy and Mining (‘MEyM’) notified the signatories to the Transition Agreement of its suspension as from October 1, 2017 since the Brent crude oil price exceeded US$55/bbl for 10 consecutive days, a condition stipulated in the Transition Agreement.

Since then, the domestic price for crude oil barrel to be used as raw material for refining and gas pump prices have been determined based on domestic market rules.

Regulations Specifically Applicable to Gas Transportation

Public Emergency and Exchange Rate Regime Reform Law No. 25,561, which was passed and enacted during the first days of the month of January, 2002 and later extended on several occasions until early January 2018, provided for the turning into pesos of utility service tariffs; consequently, the transportation tariff remained unchanged in AR$ as from 1999, despite the sharp increase in price indexes and operating costs. As a result of this situation, tariffs in this segment suffered a significant lag when compared to the important increases in other macroeconomic variables, which directly affected operating costs, and thus deteriorated the company’s economic and financial situation.

The tariff freeze continued until April 2014, when a mere 20% increase was obtained as a result of the implementation of the transitory agreement entered into in 2008. Later on, effective as from May 1, 2015, an additional 44.3% increase in the natural gas transportation tariff and a 73.2% increase in the Access and Use Position (‘CAU’ or Cargo de Acceso y Uso) were granted.

Throughout 2016, Transportadora Gas del Sur S.A. (‘TGS’) continued conducting the relevant procedures aimed at the implementation of the transitory agreement signed with the Federal Government on February 24, 2016 Within this context, on March 29, 2016, the former Ministry of Energy and Mining (‘MEyM’) issued Resolution No. 31/16 which, among other measures, instructed National Gas Regulatory Entity (‘ENARGAS’ or Ente Nacional Regulador del Gas) to conduct the Integral Tariff Review (‘RTI’) process and to grant a transitory tariff increase until the conclusion of the RTI process. In furtherance thereof, on March 31, 2016 ENARGAS passed Resolution No. 3724/16 approving the new tariff schemes for the natural gas transportation utility service and the CAU, granting a 200.1% increase effective as from April 1, 2016. However, on August 18, 2016, the Supreme Court of Justice of the Republic of Argentina (‘CSJN’ or Corte Suprema de Justicia de la Nación Argentina) established the obligation to hold a public hearing for setting tariffs and prices without market intervention, and declared the nullity of MEyM’s Resolution No. 28/16 and 31/16 regarding residential users, for which tariff schemes were taken back to the values effective as of March 31, 2016. The public hearing was held on October 6, 2016, and consequently, ENARGAS issued Resolution No. 4054/16 providing for a 200.1% transitory tariff increase effective as from October 7, 2016, the execution of the investment plan, and restrictions on the distribution of dividends.

The public hearing required by the RTI process was held in December 2016. On March 30, 2017, pursuant to ENARGAS Resolution No. I-4362/17, a transitory tariff scheme was approved, which, if granted in a single installment as from April 2017, would have represented a 214.2% and 37% increase in the natural gas transportation utility service and the CAU, respectively, applicable as from April 1, 2017, with a semiannual non-automatic tariff adjustment mechanism subject to the Wholesale Domestic Price Index (‘IPIPM’) published by the National Institute of Statistics and Censuses (‘INDEC’ or Instituto Nacional de Estadistica y Censos de Argentina). As a result, TGS executed the 2017 Comprehensive Memorandum of Understanding, and on the same date, the 2017 Transitory Agreement was entered into with the purpose of making a transitory tariff adjustment to be charged against the RTI; to such effect, ENARGAS Resolution No. 4362/17 was issued pursuant to MEyM Resolution No. 74/17, which limited the tariff increase resulting from the RTI process and provided for its application in three stages, 58% in April 2017, and the balance in December 2017 and April 2018.

Both the RTI process and the determination of the transitory tariff adjustments provide TGS with a framework to operate the gas pipeline system on a prudential and economically sound basis. So much so that the increases were granted taking into consideration the income necessary to execute a Five-Year Investment Plan that requires a high level of investments which are essential to face operational and maintenance needs. For the five-year period starting on April 1, 2017 and finishing on March 31, 2022, this plan will amount to AR$6,787 million, an approximate average of AR$1,360 million per year for the five-year period, expressed in values as of December 2016. This Five-Year Investment Plan was devised by TGS to guarantee the safety and continuity of the natural gas transportation utility service so as to meet the expected higher demand from the system as a result of the development of natural gas reserves.

The public hearing to present costs variations was held on November 14, 2017, and pursuant to ENARGAS Resolution No. 120/17, an average 78% increase in tariff schemes was established, effective as from December 1, 2017, including a 15% increase on account of the non-automatic adjustment provided for by ENARGAS Resolution No. 4362/17 for the January – October 2017 period. This increase was deemed charged against the amounts resulting from the Comprehensive Renegotiation Memorandum of Understanding for the License executed by TGS on March 30, 2017.

Furthermore, on January 31, 2018, ENARGAS Resolution No. 247/18 was published in the Public Gazette (‘BO’ or Boletín Oficial), which called for a public hearing to be held on February 20, 2018 to discuss TGS’s transportation tariff update. On March 28, 2018, Executive Order No. 250/18 of the National Executive Branch (‘PEN’ or Poder Ejecutivo Nacional) was published in the BO, whereby the Federal Government ratified the Comprehensive Renegotiation Memorandum of Understanding for the license executed by TGS on March 30, 2017, thus concluding the RTI process initiated in the month of April, 2016, and as a result, on June 26, 2018, TGS voluntarily dismissed the Arbitration Proceeding it had brought before the International Centre for Settlement of Investment Disputes (‘ICSID’).

Therefore, and pursuant to MEyM Resolution No. 74E/17, ENARGAS issued Resolution No. 310/18, which approved, effective as from April 1, 2018, the last installment of the tariff increase granted by Resolution No. 4362/17, equivalent to a 50% increase in tariff schemes applicable to the natural gas transportation utility provided by TGS, as well as in the CAU, including a 13% recognition on account of IPIM variations for the November 2017 – February 2018 period, and a compensation for the tariff increase deferral payable in installments.

On September 4, 2018, the public hearing to analyze cost variations between February and August 2018 was held, and on September 27, 2018, ENARGAS issued Resolution No. 265/2018 granting a 19.7% increase in tariff schemes applicable to the natural gas transportation utility provided by TGS, effective as from October 1, 2018.

Finally, pursuant to Resolution No. 1/19 issued on February 4, 2019, ENARGAS called TGS for a public hearing to be held on February 26, 2019 with the purpose of disclosing the application of the semiannual tariff update corresponding to the August 2018 – February 2019 period.

Regulations Specifically Applicable to the Liquefied Petroleum Gas (‘LPG’) Business

Household Gas Bottles’ Program and Propane for Grids Agreement
In the domestic market, during 2018 Transportadora Gas del Sur S.A. (‘TGS’) continued taking part in several product supply programs developed by the Federal Government, such as the program for the supply of butane for gas bottles at subsidized prices pursuant to Executive Order No. 470/2015 of the National Executive Branch (‘PEN’ or Poder Ejecutivo Nacional), later regulated by Resolutions No. 49/2015 and No. 70/2015 of the former Secretariat of Energy, the Household Gas Bottles’ Program regulated by Resolutions No. 56/2017 and 287/2017 of the Subsecretariat of Hydrocarbon Resources (‘SRH’) and SRH Provision No. 5/2018, and the Agreement for the Supply of Propane Gas for Undiluted Propane Gas Distribution Grids (the ‘Propane for Grids Agreement’), whereby the SE issued a series of resolutions aiming to regulate the price of propane.

The Household Gas Bottles’ Program establishes a maximum reference price for parties involved in the LPG supply chain seeking to guarantee supply to low-income residential users by compelling producers to supply LPG at a set price to fractionation companies, with a defined quota for each of them. Additionally, the payment of a compensation to participating producers is established.

The sale price for butane and propane under the Household Gas Bottles’ Program is determined by the SRH, which issued Resolution No. 287/17 and Provision No. 5/18 setting a price of AR$4,302 per metric ton (‘ton’) for propane and AR$4,290/ton for propane as from December 2017, and of AR$5,416/ton for butane and AR$5,502/ton for propane as from April 2018. The compensation received from the SRH amounted to AR$550/ton, which has been the compensatory amount since April 2015. Furthermore, on January 25, 2019, Resolution No. 15/19 of the Government Secretariat of Energy (‘SGE’) was issued, which updated prices to AR$9,154/ton for butane and AR$9,042/ton for propane, effective as from February 2019. Furthermore, the compensation receivable from the SRH has been nullified.

Due to its participation in this program, TGS is bound to produce and sell the LPG volumes required by the former Ministry of Energy and Mining (‘MEyM’) at prices ostensibly lower than market prices. As a result of this situation, TGS has been forced to adopt the necessary mechanisms to minimize its negative impact.

As regards the Propane for Grids Agreement and under the gradual subsidy reduction path, MEyM Resolution No. 474/17 provided, effective as from December 1, 2017, an increase in the price of undiluted propane gas to be destined to the Propane for Grids Agreement in the amount of AR$1,941/ton and AR$3,964/ton, depending on the client the product is targeted at. On the other hand, on May 30, 2018, TGS executed the 16th extension to the agreement, which set a new methodology for price determination and volumes to be sold for the April 1, 2018 – December 31, 2019 period under this program.

Both the Household Gas Bottles’ Program and the Propane for Grids Agreement provide for a compensation to participants, payable by the Federal Government, which is calculated as the difference between the price defined by the SGE and the export parity published by the SRH on a monthly basis. Even though it is not being collected timely and in due form, collection terms have improved during fiscal year 2018.
 
Natural Gas Import Financing
As regards Resolutions I-1982/11 and I-1991/11 issued by the National Gas Regulatory Entity (‘ENARGAS’), which provided for an approximate 700% increase in the natural gas import financing charge (created by PEN Executive Order No. 2067/08), TGS continued pursuing legal proceedings timely initiated seeking that this charge should be declared unconstitutional and, consequently, inapplicable. In 2018, TGS was granted new injunctions, the last one maturing in March 2019.
 
Export Duty
Executive Orders No. 793 and 865/2018, issued by the PEN on September 3 and 27, 2018, respectively, regulated the application of a duty on exports for all the goods under the Common Mercosur Nomenclature, including natural gas, propane, butane and natural gasoline, effective as from September 4, 2018 to December 31, 2020. This duty provides for a AR$4 withholding on each exported US$, with a maximum 12% tax rate.

Regulations Specifically Applicable to Crude Oil Transportation

In the month of June 2016, the conduction of an Integral Tariff Review (‘RTI’) process was requested to the former Ministry of Energy and Mining (‘MEyM’) as the then-current tariffs were outdated and insufficient to develop a maintenance and investment plan that may guarantee the integrity of facilities, minimize wastages, prevent and detect fraud, and improve energy efficiency towards the evolution of the transportation service in terms of reliability and efficiency.

The Enforcement Authority considered Oleoductos del Valle S.A.’s (‘OldelVal’)’s allegations admissible, and on March 10, 2017 MEyM Resolution No. 49/17 was published in the Public Gazette (‘BO’ or Boletín Oficial) defining a new US$-denominated tariff scheme with an average 34% increase and effective for a term of 5 years as from March 2017.

In November 2018 Pampa closed the sale of 21% of Oldelval’s capital stock to ExxonMobil, keeping a 2.1% equity interest in OldelVal.