Argentina’s energy matrix is highly diversified. Power sources include hydro (around 34 per cent), natural gas-fired turbines (60 per cent), nuclear (5 per cent) and other (2 per cent). However, since 2003, Argentina has evolved from being an energy net exporter to a net importer, owing to the market interference by government policies (now abandoned) that stalled investments. Up to 25 per cent of the natural gas aggregate demand is supplied by natural gas imported by the government from Bolivia, and from LNG sources to be regasified, at significantly higher prices than the domestic prices imposed on the local upstream offer, amid a maze of price differentials according to the supply source (existing production, ‘new’ or non-conventional production under specially approved programmes, now coming to an end, apart from the existing approved shale gas projects under Resolutions ME 46/17 - as amended by Resolution MIM 12/18 and 447/17). These programmes contributed to a growing governmental deficit until 2014, since reduced because of the fall in international energy prices, in this case, of imported LNG. Since 2013, crude oil production has been spared this interference (that in previous years had established an export withholding tax resulting in a price of US$42 per barrel for the domestic crude oil producer at a time when the international price was at least double), by the government terminating such export withholding and sponsoring an ‘agreement’ between the downstream and the upstream oil industry ensuring US$67 per domestic barrel (though it was not entirely respected, as refineries reduced purchase price to lower values than those of the agreement, described below) until the end of 2016, passed on a heavily taxed gasoline and gas oil price to consumers. In December 2016, convergence with international prices was sought by a renewal of an agreement between the upstream (supported by the oil producing provinces and the unions) and the downstream for establishing a floor of US$55 per barrel (US$47 for the heavier kind) for 2017, under the supervision of the government. The government acted as an ‘umpire’ by loosening the grip on imports and, on the other hand, allowing quarterly gasoline increases (to keep pace with inflation) to align them with upstream crude oil prices on a netback basis. As is evident, such higher-than-import parity prices for crude oil were sustained through an import control limiting the highly concentrated four refineries’ procurement of imported crude oil. As international prices for crude oil increased in 2017, reaching the same level as local ones, the government announced no prior control on crude oil imports (and their by-products) would be made as from the end of 2017 onwards. Decree 962/17, superseded Decree 192/17 and Resolution €47/17, which had established the pecking order for importers according to accrued data that had made official an, until then, little publicised import control measure adopted by the government. At current prices, there are no incentives envisioned for secondary or other enhancement recovery techniques on existing conventional, predominantly oil producing fields, to counter the 7 or 8 per cent decline in Argentine oil aggregate production in 2017. However, there is with an upward curve reflecting 2018’s shale oil expansion, which will also require the expansion of the current Oldeval oil pipeline. Apart from this, under Decree 872/18 (Re SE 65/18), large offshore areas have been offered for open bidding in the three potential basins in Argentina’s Atlantic territory and exclusive economic zone, under Hydrocarbons Law 27007. The general framework for offshore exploration permits grants:
- two periods, four + four years, plus up to five years’ extension after a 50 per cent relinquishment, under heavier surface charges than those in the former period (trade off with works, admitted), and a right to request a 30-year (plus 10 years’ successive extensions, with a 3 per cent royalties increase for each extension on top of the former royalty, up to 18 per cent) exploitation concession, subject to a sliding scale of 5, 6 or 12 per cent royalty as per certain hydrocarbons sales over investments ratios (but it can be reduced by up to half, depending on the bidding terms); and
- exports proceeds spared from remittance - except for the current, exceptional general exports withholding of 10 per cent at the current exchange rate, decreasing at par with domestic inflation from the third quarter of 2018, imposed as a consequence of the crisis at such time, informed below - up to 60 per cent (exports are currently totally exempt from remittance and foreign currency exchange restrictions, thus this 60 per cent acts as a floor in case of future restrictions).
The bidders (with economic and technical satisfactory qualifications) will offer an access bonus, work commitments or investments to develop the prospect and compliance bonds (and, if awarded, performance bonds). The highest commitment plus a bonus is awarded.
As for natural gas, the road has been bumpier. The government had set forth (Resolution of the Ministry of Energy and Mining 28/16) the upstream cost for the natural gas tariffs at circa US$5 per MMBtu, to be passed through to distribution tariffs, thus reducing the gap with historic depressed prices for natural gas production, depending on the different destinations (residential or large customers). In a partial attempt to correct them the Resolution was, however, based on prior resolutions adopted by the former government in excess of regulatory powers. In a class action case, the Federal Supreme Court (although it was limited to residential customers) annulled the pass-through of such upstream costs to tariffs (details of the case are discussed below). The government swiftly followed the criterion set out in the award and, after calling public hearings to discuss these issues, reduced the increase for pass-through to a median price mix of US$3.97 per MMBtu (US$5.22 for the gas producer) with an increased price path (as from March 2017, US$4.72 and US$5.64 for the gas producer, as per Resolution €74/17) for the next three years, up to US$6.8 per MMBtu to the end of 2019 (Resolution €212/2016; superseded by Resolution 474-E 2017). Both power and natural gas distribution tariffs continued to experience increases to realign price-subsidised values to market prices. However, under article 8 of the federal budget implementation Decree 1053/18 (replacing Resolution ENARGAS 20/18, which deferred price hikes from foreign exchange variations), as from the second quarter of 2019 gas distributors will be prevented from passing through to tariffs dollar upstream gas price variations within each six-month tariff period, and supply contracts with the producers shall reflect this restriction. Until then, the government is taking on the burden of the foreign exchange loss represented by interim foreign exchange variations due and unpaid by gas distributors.
Conventional source upstream gas prices followed the trend, while respecting public hearing procedures as per the Supreme Court guidelines, which defused conflicts, while distributors’ value-added feed-in tariff increases resulted from the Tariff Reviews by the relevant government agencies ENARGAS and ENRE. In the second half of 2018, new ceilings on intake gas pipeline point prices were set out for the passing-through of tariffs, reducing them to US$3.60 to US$4.42 per MM Btu, depending on each basin, for upstream gas not subject to the special programmes for shale gas developments. The gas plans were kept for 2017, rewarding non-conventional production (shale gas and tight gas, as well as the increased production beyond historic levels per basin and field, adjusted as per their natural depletion) with a differential guaranteed up to US$7.5 per MMBtu. Resolution of the Minister of Energy €46/17, complemented with Resolution 419/17 (and Resolution €447/17 up to the Austral basin), extended the US$7.5/MMBtu government’s price support for non-conventional (tight or shale) gas to be continued in 2018 (Argentina is the second largest shale gas reserve in the world), and with a declining path until 2021 with US$6/MMBtu, guaranteeing such floor (net of royalties) with respect to the median price of the aggregate natural gas (conventional or not, of domestic sources) sales in Argentina (initially, the comparison was with the applicant’s one). But such extension is now reserved for the incremental production of the fields (without taking into account their downward curve), or for new ones, as from 2017 onwards, confirming the old adage that what is new today becomes old tomorrow in the eyes of a regulator; a source for conflicts. A significant increase of shale gas production under the promotion programmes continues with a steep growth trend for the coming years, evidencing that the short-term ROI of each fracture is a bonus but at the same time a warning, as it is extremely sensitive to regulatory changes (and, though less so, market changes, once deregulated), with lesser sunk costs, which should defuse the temptation of government’s predatory practices. This is not the sole factor predicating the need for continuity of regulatory practices, assuring open market, since the infrastructure needed to transport the same to consumers needs gas pipeline expansion, which also requires long-term, firm shipping agreements with producers and with a stable demand at the end of the pipe. A new gas pipeline is already being built to join shale gas fields to the trunk gas pipelines to the consumption centres, and further to consumers’ hub and future LNG exports, through the Gasoducto del Litoral pipeline project, as the existing gas pipeline’s transportation capacity is quickly reaching to its peak in gas intensive consumption seasonal periods (winter). In the winter of 2019 the domestic gas pipelines reaching consumers will have reached their maximum capacity, leaving for no room for open third-party access. The regulatory framework allows for one, or several gas exploitation concession holders together, to have their own gas pipeline for injecting their gas (article 1, Decree 589/17, amending Decree 729/95), leaving the tariff approval process to third-party gas transportation shippers in excess of their own gas.
Gas exports, forbidden (through lack of approvals and ridiculously expensive export withholdings) for more than 10 years, are now being allowed (Decree 962/17) provided they include interruptible supply clauses with no penalty for interruption, by coexisting with seasonal, substantial LNG imports and with the gas contract with Bolivia (Resolution 407/17 MEyM regarding exports by the State Agency Enarsa, and authorisation of swaps). Decree MEyM 962/17 for interruptible supply exports was followed by Res MEyM 104/18 for long and short-term exports, both with firm or interruptible terms, or summer exports with a swap duty to import gas or power in winter, with restrictions, however, linked with the periodic (five year) check that the aggregate domestic supply continues to be assured, and subject theoretically to domestic demand on similar terms at the time (five days) of the approval request, in which case such domestic gas purchase by the interested party prevails. Gas exports (from sources other than the one subject to the Res 46/17 price guaranty) are, however, subject to eventual interruption in case of domestic undersupply. Long-range planning and stable rules are also necessary in this field.
Argentina, as the second largest holder of shale gas resources in the world (swiftly becoming reserves, owing to the steep learning curve acquired with the existing exploitation), will soon achieve a third of its overall natural gas production with shale gas. It is therefore in an advantageous competitive position to (i) export gas to Chile and to Uruguay or Brazil through existing international gas pipelines that remained idle in the past decade because of domestic demand requirements in a government-led market and (ii) install liquefaction plants to export LNG (be it through two existing projects - by YPF and TGS - or through Chile, reaching the Pacific Ocean by setting up a liquefaction plant in such country). This would also allow a rapid change of an import parity domestic price matrix to an export parity one, with a profound impact, as the gas pricing in Argentina should develop in an open market, setting aside its current segmentation resulting from the coexistence of special shale gas programmes, imported LNG degasification and conventional gas prices’ spread, on one hand, and the converging of current price differentials according to destination to industrial, residential or thermal power generation. One single market should define prices, where demand and supply meet.
The government was considering reinstating the 1990s natural gas spot market from the second half of 2018, later subject to new postponements, while interim fixing supply quotas allocated to distributors at set prices and dispatch priorities. This is reminiscent of the overregulated market in segregated gas prices that led to the stalling of investments in the 2002 to 2009 period (a description of which can be found in ‘Eminent Domain and Regulatory Changes’ by Luis Erize, in Property and the Law in Energy and Natural Resources, Oxford University Press), now dampened by the price path for new investments in non-conventional exploitation. The transition to open market policies demands a series of measures to make different priced gas sources (conventional, non-conventional, imported) converge into a single priced market, at the level of net back, import parity price signals, to be passed through to tariffs for customers downstream, and for the market to set price to gas-fired generators (and industrial consumers, the single demand sector not regulated ostensibly at present). But this would require the leading role of a market of standardised term contracts for distributors, large customers, and power generators, also requiring similar reforms to the power sector to avoid opportunistic behaviour that could jeopardise the reliability of supply (which also requires power capacity agreements and non-interruptible gas supply contracts to be put in place). Thus, spot markets in both natural gas and power should be left to resolve the shortfalls of contract suppliers, and not be established as the market through which the bulk of transactions would be effected. (Apparently, the government is starting to consider solutions for contract markets that were proposed in the Luis Erize paper ‘Electric Power in Argentina: a Diagnosis of Regulatory Distortion, Investment Deficit and a Sustainable Development Proposal’, published in RADEHM, Revista Argentina de Derecho de la Energía, Hidrocarburos y Minería, No. 7, Nov-Dec 2015, pp 285-330). The government, through CAMMESA (the power dispatch and broker centre, who was converted into performing as supplier of gas to thermal power generators, monopolising the purchase from producers to such ends) has made for open bidding of summer gas supply to such consumers as per Res ME46/18 (and hoping to make the power generators to make for a joint purchase of gas from LNG sources replacing the government, thus sparing the loss incurred by the latter). However, it is not simply by calling for an electronic board serving as exchange market or hub that competition will be obtained: standardised term contracts, fully tradeable and with adequate guaranties of supply or payment of substitute gas at penalised prices, should be set accordingly in an entirely deregulated open market - both for power and natural gas, given their interdependence in Argentina. This also requires security of supply to be considered and dispatch orders to be set in both sectors in accordance with objective rules. In fact, the Mercado Electrónico del Gas, created by article 6 of Decree 180/04, never materialised owing to the interference by the government on prices, dispatch rules, segmentation of markets, etc. The re-instalment of such exchange by Resolution SE 1146/04, Subsecretary of Fuels 116/04 and Note SSC 987/06, and 260/05, ending with Disposition 156/06, did not serve any practical purpose at a time price and dispatch were the resort of the government.
In conclusion, the shale revolution of the energy sector has the momentum to replace LNG imports to a great extent. One of the LNG plant barges has been returned to its owner and, to the opposite ,YPF has reserved already a mobile liquefaction plant for gas to be delivered at the Bahía Blanca petrochemical pole to export LNG. The exports hence should be to Chile and Brazil via Uruguay, through the existing international pipelines, and to any other destination, once the liquefaction plants are installed, together with new pipeline projects already under way (the Gasoducto Litoral for an additional 1,000km, the one connecting Vaca Muerta shale gas area with the trunk gas pipelines), plus the increase of liquids processing of the rich shale gas.
The current scenario anticipates a regulated gradual increase of renewables’ share in the power generation matrix to reach, as from the end of 2018, 8 per cent of the aggregate power supply, and to increase in the following years up to 20 per cent on a sliding scale (it is less than 3 per cent at present, excluding hydro, thus in practice postponing the target date).This has led to successive rows (the first one, later on extended; a second one, by Resolutions ME&N 252/16 and 275/17; and a new one through Resolution SE 100/18 (easing the prior stringent requirements of minimum economic worth, and disabling adjustment and premium clauses applicable to the former rounds) of public bids by CAMMESA for 20-year supply agreements’ offers (labelled as joint sales), at a price subject to escalation, to attempt to reach such targets in the supply side. Priority of dispatch for the supply of renewables is set forth in Res MEyM 281-E/17. Big consumers (industry, etc) over and above a capacity demand above 300KW must comply with the 8 per cent renewables quota with respect to their own overall power demand. Regulation of the aggregate demand of sourced renewables’ power allows some kind of competition with power purchased by the government (joint sales), with either remaining renewables offers that may be installed for the industrial consumers, or renewable energy auto generated by large consumers. Such competition is subject to an iron-fisted choice (as per Resolution MEyM 281-E/17 and Disposition SSRE 1-E/18) by large consumers, to be made every five years, to decide if their 8 per cent renewables consumption quota will be filled either way, as they are unable to switch from one to the other source during such period.
To give some flexibility, large consumers were allowed to avoid making such a choice, thus both consuming renewable energy from CAMMESA’s joint sales pool and from other renewable energy, but would then face incremental costs for power reserves and other charges.
Thus a quota system segregates captive demand for renewables from the rest of the aggregate energy supply, and a forced choice between:
- government-backed (the joint sales) supply (at the median price of all the bids referred to above); and
- the supply obtained in a supposedly free market, or by auto generation by large consumers themselves, seems to be a confusing method to assure (by making it quite risky for a large consumer to opt out) that future production already acquired by the government from the winning bidders (the joint sales) will effectively meet their captive demand.
In effect, an individual default of the yearly quota of renewables consumption by each large industrial consumer, and the ensuing power consumption to match such deficit, from sources other than the renewables contracted out of the governmental offer mentioned in (i) above, will be heavily penalised.
The government aims to resolve the intermittency of renewables, for which bidding was permitted with no commitment on capacity, by offering capacity back-ups for the pass-through of such contracts to large consumers at a price that will be the subject of separate bids, with unpredictable results. The complexity of the system is compounded by the grid’s shortcomings, with a priority of dispatch adding to the uncertainty in making such choices in the medium to long term. Also, the redistribution of power by customers able to inject their own generation back to the grid (Law 27424, as regulated by Decree 986/18) adds stringent requirements for metering and ensuring the system’s reliability .
If, on the other hand, the natural gas (from any source) market were free from any remaining regulatory interference, it would reach an import parity price (at present fluctuating around US$6/MMBtu for imported LNG regas sources), as Argentina is a net importer of up to 25 per cent of its aggregate gas consumption. This would thus free the government from the heavy burden of sustaining these programmes (as the price differential between the international price and the domestic market price would be substantially reduced). Import parity is the ironclad law of markets, sweeping away economically and technically flawed concepts of reference prices by computing Henry Hub prices plus transport costs into the country (liquefaction and transportation amounting each to a third of the LNG price), since LNG is a commodity that varies its prices on the spot depending on the availability of cargo. The shale and tight gas projects expect a soft landing into market prices that, when freed from regulatory measures, would reach import parity level, making them profitable. The significantly rapid decline in shale field exploitation and the need for continuing short-term investments requires stable rules to make a long-term forecast.
Argentina is currently one of the world’s top-ranking non-conventional (shale) resource countries (second in shale gas, fourth in shale oil) and one of the first countries to explore and develop these resources apart from the United States.
The prospect of further development can be expected as a result of the following:
- the law reforms (in 2014) extending current exploitation concessions - mainly to the benefit of the state-controlled YPF (the most significant oil and gas upstream and midstream player in Argentina) - and further renewals;
- the soft landing of the end (for the time being, depending on the satisfactory evolution of international crude oil prices) of domestic prices; and
- the need to reduce the governmental budget deficit (also requiring a significant reduction to power and natural gas consumption subsidies) and the aggregate trade deficit caused by significant energy imports, which will also lead to higher overall price increases for gas and power, while reducing gas and power consumption subsidies to well-defined social tariffs for the disadvantaged.
Back to top