With a contractualised market, we will move from having supply problems to demand problems.

Daniel Gustavo MONTAMAT Executive Director Montamat & Asociados

Time to hit the gas

November 6, 2017

Daniel Montamat, president of Montamat & Asociados, talks to TOGY about natural gas pricing and programmes to incentivise further production in Argentina, the development of the power generation sector and prospects for further regional energy integration. Montamat & Asociados has provided legal and market advisory services to energy companies and governments in South America since 1991.

• On gas supply and demand: “With respect to the demand peaks that occur during winter, peak shaving will be done by LNG brought by ship. During the rest of the year, I think that Argentina will be self-sufficient, perhaps even sooner than expected, and will have exportable amounts of gas that will need to be placed in some market. With a contractualised market, we will move from having supply problems to demand problems.”

• On the Vaca Muerta framework agreement: “This was very positive. Being able to discuss productivity once more in this country is a triumph in itself. Productivity was a word that was used as a euphemism for unemployment. The productivity agreements were unique in Vaca Muerta because now this is an issue that can be discussed in other oilfields using the same logic and the same basis.”

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What is the outlook for Argentina’s energy industry once the gas pricing issue is resolved?
The issue concerning the gas price is only halfway solved because there is a price horizon for unconventional natural gas from Vaca Muerta, which ends in 2021 with a price of USD 6 per million Btu. This provides certainty for a few years for the new natural gas coming from the Neuquén Basin.
The problem is that the other plans will cease. The Gas Plan and Gas Plus Plan incentivised, with a better price, the natural gas produced above a certain declination curve. Companies have some uncertainty about what is going to happen after these incentive programmes for new natural gas produced from conventional formations cease. The issue is what happens with conventional gas.
I believe that the Ministry of Energy and Mining is proposing that when these plans fall, we will go to a supply and demand interaction, trying to contractualise the market. I believe this is a signal in the right direction, because in this whole energy reorganisation process, there has been an actual emergency. We are still under an electricity emergency. There has to be a transition towards a price readjustment and the building of the sector’s institutions. We need to establish the regulations that are required so that costs can be recovered with a reasonable profit.

How will gas prices evolve in the future?
During certain months, price parity will be more associated with imported natural gas, such as LNG. We must solve the price issue to proceed to the improvement of the sector’s institutions. This will involve once again having entities such as the National Gas Regulatory Entity, known as Enargas, with its authorities designated through a competitive selection process. Entities such as ENRE [National Entity for Energy Regulation] and Enargas must be autonomous.
The final goal is achieving a natural gas market where supply and demand interact. The Bolivian basin will have to interact with Argentine basins, which is desirable.
With respect to the demand peaks that occur during winter, peak shaving will be done by LNG brought by ship. During the rest of the year, I think that Argentina will be self-sufficient, perhaps even sooner than expected, and will have exportable amounts of gas that will need to be placed in some market. With a contractualised market, we will move from having supply problems to demand problems.

How is the domestic natural gas industry evolving in 2017 compared to 2016?
Natural gas production has been growing well. In 2016, it grew almost 5% and the year before, it grew 4%. We should bet on increasing natural gas production.
Unconventional development in the United States started with natural gas, and we have a lot more natural gas than oil. Even the development of natural gas gives also some associated fluids and, once you have the installations and infrastructure for natural gas, that reduces the costs for developing shale oil. This is the process that took place in the United States.
The pending issue we had was the price of natural gas. This is why in 2017, natural gas production has stagnated a bit. This is because investments in unconventional natural gas via new pilot projects have been deferred a bit. The companies that are more committed to these projects are Tecpetrol and YPF. YPF needs strategic partners and is looking for them. The remaining companies are in wait-and-see mode.

How do you think gas supply will evolve in the near term?
There is a stagnation of overall natural gas production, which I consider to be a parenthesis. I believe the potential is there and the projects are there. Several projects will begin generating very significant productive contributions, such as Tecpetrol’s, which is transitioning from a production of 300,000 cubic metres [10.6 mcf] per day in 2017 to more than 10 mcm [353 mcf] per day by 2019.
The issue is sending out a signal to the other basins, because conventional production is still predominant. There should be some support for that. We need to increase recovery in conventional fields. We have to align natural gas prices with the opportunity costs. The government’s idea is to have a natural gas price of USD 6 per million Btu in 2021 in Vaca Muerta, and for the rest to converge to something similar, and then prices will be more or less linked with their opportunity costs.
Therefore, I do not discard the possibility of new conventional projects. For example, we have Vega Pléyade, which has higher production than expected and it seems that there are extremely interesting prospects in that development.

 

Do you expect costs drivers to continue improving?
President Mauricio Macri’s government is committed to supporting this by setting a long-term policy. If you give companies a horizon of only two years, the investments will continue to be financial, seeking niches to profit from. With a six-year horizon, the process will experience a substantial reactivation, depending on the battle regarding costs. With a six-year horizon, I would also expect a reduction of the cost of capital for Argentina. This is important because there is a lot of liquidity in the world.
You also need to study the flexibility of opex. Maybe it is not so much a salary reduction, but an increase in flexibility in terms of changes, work hours, adapting the equipment and in capex. There, you have a very expensive and inefficient state that needs to reorganise, and which applies a heavy taxation burden on those operating in the formal economy. If we are able to overcome these challenges in reducing costs, I believe there will be interesting investment potential.
Of course, there is a variable we do not control, which are international prices, and the perspectives are not to optimistic. I am assuming a barrel price of USD 50-60 for this scenario, but if it drops to USD 40-30, it would be a completely different story. With these prices and working on the costs and having a five- or six-year horizon, I think we will see a substantial investment contribution.

What do you think about the framework agreement signed by companies, unions and the government in Neuquén?
This was very positive. Being able to discuss productivity once more in this country is a triumph in itself. Productivity was a word that was used as a euphemism for unemployment. The productivity agreements were unique in Vaca Muerta because now this is an issue that can be discussed in other oilfields using the same logic and the same basis.
When one has negotiated costs and productivity conditions in an oilfield, if the rest of the oilfields do not follow the same steps, all the investment is redirected to the area that has an agreement. As a result, similar agreements are being negotiated and adjusted for the particular conditions of each case in the remaining productive basins.
There was already one agreement in the San Jorge Gulf Basin, and it will soon have to happen in Santa Cruz and the Austral Basin.

What are the bases for these productivity agreements?
All this is a part of the costs battle. There you have the opex issue, but there’s also many issues related with capex. There are several drilling devices here with personnel that can be a bit inflexible, but that is an issue that should be dealt with by the company that contracts this service as part of its capex, and there’s also opex involved there.
The other issue is taxation: provincial taxes, municipal tariffs and so on. All this has to be rearranged. There is always an attempt to resort to royalties, which is a tax on gross income, while the oil company asks for a tax on net income and windfall profit. These latter taxes are much more efficient in terms of the service life of an oilfield. If you apply significant royalties, then you discourage activity. I think that they are beginning to understand that if they want long-term predictability and investment that does not only rely on the state, the tax regime must move towards a form of viable capitalism.
Then, the following logic ensues: There has to be a profit and profit is price minus costs. These subsidised barrel prices cannot be maintained indefinitely. We need to readjust to international references. This should be on the part of the companies. The other parties involved must start thinking about the costs, labour unions and national and provincial states. This logic will allow a discussion in terms of making investment viable. Without investment, it will all be over.

How is the domestic power generation sector evolving?
You have another challenge there, because the thermal energy tender was held due to the emergency situation. The modular equipment deployed to overcome this situation was extremely expensive. Although we have gone from a bit below USD 200 per MWh to more than USD 100, electricity is still not cheap. That was in the context of an emergency and we needed to increase generation.
The issue of renewable energies was tied to a law that forces one to purchase renewable energies to make room for them in the market. All this is carried out by PPAs [power purchase agreements] with CAMMESA, Argentina’s wholesale electricity market administrator. This means that CAMMESA is in the middle and is brokering electrons between different types of generation and demand. The PPAs for renewable energies are 20-year contracts, which is a lot of time.
Assume that companies keep adding more PPAs with CAMMESA and renewables have priority. Then, for example, YPF wants to sell natural gas to a thermal power plant under a three-year contract at USD 6 per million Btu. The thermal power plant will say that, with all these PPAs and their repercussions in terms of supply priority, three years is too long. They will ask for a one-year contract or interruptible conditions. This all hinders contractualisation.
In the renewables segment, PPAs with CAMMESA have delivery priority and that displaces thermal power. As long as we have this low proportion of renewables in the energy matrix, since we are starting from zero, everything will be all right, but if it increases too much, the intermittency starts to generate some problems, and contractualisation via CAMMESA generates an additional problem.
It would be ideal for new renewable energy sources to begin privately contractualising. If you want to produce wind power, you need to look for demand.

What are the prospects for further regional energy integration?
Further integration is beneficial for all of us. If you want to have economic integration, you need to have structured markets. Otherwise there is no real economic integration. To have structured markets, they need to be structured in infrastructure – roads, railways and so on – and energy and telecommunications.
Europe is an integrated market that fulfils all these previous conditions. We urgently need the integration, because we need to achieve a critical mass to be able to negotiate inter-regionally. Argentina cannot go by itself to negotiate trade agreements with China, as it has no leverage. In a long-term strategy, you can achieve this, but you need to have a critical mass. Mercosur [Southern Common Market trade bloc] plus Chile can stand up to China and establish a different type of negotiation.
If we had a regional critical mass with an energy surplus because Argentina had developed Vaca Muerta and Brazil had developed the pre-salt layer, we could talk Europe and the United States into buying energy from us instead from their current suppliers. For instance, we could enter the LNG market as suppliers. Europe and the United States are and will continue to be the main importers of oil surplus and they can get those resources from this region.

What should be Argentina’s energy objectives through the end of 2018?
I see Argentina consolidating its natural gas recovery and I believe that the goal is to recover the status of natural gas-producing country through 2022. Therefore, we will see a gradual introduction of renewable energies and oil recovery, but tied to natural gas recovery. We will continue to see stagnated or declining oil production until the country consolidates this natural gas revolution.
I say this looking at precedents. The United States had the shale gas revolution and that brought with it a whole infrastructure that lowered costs for shale oil. I think we are in a sort of impasse. Natural gas production in 2017 is stagnant. Investments have already been decided, but are being delayed for a couple of months. I think that in 2018, gas production will continue its recovery.

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