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Q&A: Mexico oil regulator says slow wins the race



By Argus

Petroleumworld 04 11 2019

Mexico's oil regulator CNH administers more than 100 contracts for oil and natural gas exploration and production (E&P) that will attract $161bn in investment if all licenses prove viable, but President Andres Manuel Lopez Obrador says the results so far are underwhelming. CNH commissioner Alma America Porres talked to Argus about the new approach to development that private-sector operators are bringing to E&P and her views on Pemex's shallow-water production strategy.

President Andres Manuel Lopez Obrador has repeatedly criticized the lack of production from independent producers. Is his criticism fair?

In truth, it is explained by the way in which the auctions were designed. The strategy was to give contracts either at the beginning of the value chain, the exploration phase, or at the end, for the fields that require revitalization. The mature onshore fields awarded in the tenders have small reserves and very low levels of production.

The president's chief of staff Alfonso Romo said last month that the government could re-launch the upstream auctions if independent producers reach 55,000 b/d by the end of this year. Is that possible?

In December, production from the contracts awarded in the upstream rounds was 3,500 b/d and 45,000 b/d if you include migrations and associations. This year we expect 7,400 b/d just from the contracts awarded in the auctions and 84,300 b/d with the migrations and associations. For 2020 production just from the auction contracts is expected to reach 63,000 b/d.

From w here will the bulk of that new production come?

Basically shallow waters, from the blocks awarded in the first round of upstream auctions. The production will come from Fieldwood Energy, Hokchi and Sierra Oil & Gas's Zama discovery by 2020 and Eni by 2021.

Can we expect to see any important production onshore?

Onshore production from the contracts awarded in the auctions is very small around 3,500 b/d and so here we are looking at revitalization work that could increase production to up to 7,000 b/d.

When a field is in a very mature state, a change of interval [in well positions] can increase productivity. Just with this type of activity many of the contracts from the first round of auctions have managed to increase production. At a national level it is not important but at field level you are increasing output a lot. Perhaps for an operator as large as Pemex it is not so interesting but for a small operator to be able to say, 'I increased production from 100 b/d to 500 b/d,' it means a lot.

From the plans CNH has approved so far, have you noticed anything new or innovative in the private operators' approach to E&P?

In the mature onshore fields, the interesting thing about these contracts is that the operators are exploring other formations in the geological column, not just the formation where oil has already been discovered.

Speed is not always the best and so if you make a discovery and then take the time to evaluate it correctly, it can bring great surprises. In Hokchi, Eni and Fieldwood's blocks, the original reserves estimate was already determined but the companies dedicated time to delimit the discoveries, drilling up to five additional wells in Hokchi's case and the estimated reserves in all those cases have increased by up to five times the original estimate.

The same has been seen in deepwater with BHP's Trion block. BHP decided to invest more in the evaluation phase in order to allow it to better design the production phase; the number of wells, the infrastructure. The more you evaluate at the beginning, the better the production plan you end up with and that is what the private sector operators are bringing.

Hokchi, Fieldwood Energy and Eni have all managed to significantly increase the reserves originally estimated by Pemex. Why did Pemex not manage that?

Perhaps Pemex's priorities were different compared with a private sector operator who can just focus on one or two projects.

Pemex started exploratory activities in Poza Rica, Veracruz, with the first onshore discoveries but then, when the shallow water discoveries were made in the southeast basin, they proved more profitable and so Pemex moved its capacities there and onshore drilling experts became shallow water drilling experts because that was where the business was.

What do you think of Pemex's current strategy to focus only on shallow-water production?

I do not think it is a bad idea as, at the end of the day, Pemex is focusing on the area where it has the best technical and investment capacities.

It is the same theory that was behind the acreage assignment strategy for Pemex following the energy reform.

Almost all of the acreage Pemex was awarded was for proven and possible reserves within the southeast basin. Pemex was only assigned 23pc of the country's exploratory or prospective reserves, while the upstream contracts awarded 11pc of those exploratory reserves. It is probably worth thinking a little better though about what to do with the rest of the reserves as only a very small portion of the reserves have been tendered so far. Some 19pc of 3P reserves and 67pc of all prospective reserves have yet to be assigned to anyone, either Pemex or independent producers. Mexico has 112bn bl of prospective reserves, 63pc of which is oil and 37pc of which is natural gas. Around 60pc of those reserves are unconventional.

Is the strategy too focused on the short-term?

The plan should be analyzed in a more integral manner, looking at the short-, medium- and long-term.

Production capacity will start to slow as the longer you wait to assign those other areas, the longer it will take to increase production.


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