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Mexico's Journey to Stronger Exploration Data

Wed, 01/18/2017 - 11:21

Q: How has the Energy Reform impacted PEMEX’s exploration activity and how will reduced reserves influence its upstream strategy?

A: PEMEX’s 1P, 2P and 3P reserves have been declining consistently over the past two decades, with a temporary plateau around eight years ago. Over the past 15 years, Mexico’s 1P reserves declined by 67 percent while 2P and 3P reserves declined 59 percent and 51 percent, respectively. Although the decline in reserves has accelerated since the Energy Reform we have to recognize that this is a much longer-term trend.

The integrated reserves replacement rate, the reserves volume added as a result of discoveries, developments, delineations and revisions divided by the total production of hydrocarbons for that period, dropped substantially in the last two years, reaching 23.4 percent for crude oil in 2016. Similarly, the 1P reserves replacement rate from new discoveries experienced a strong drop between 2010 and 2016, reaching only 5.6 percent in 2016. This means that not enough exploration activity has taken place in Mexico.

Why has PEMEX drilled fewer wells? The main difference between the wells drilled in 2010-2013 and 2014-2016 is that PEMEX changed its exploration strategy. In the period before 2010, PEMEX had a strong focus on the naturally fractured cretaceous formations of the Southeast Basin, including onshore areas, where PEMEX is most experienced. Between 2010-2013, PEMEX followed various exploration strategies in parallel. One was to explore the extension of known fields, resulting in a very high probability of success. At the same time, PEMEX successfully started deepwater exploration, although it also drilled unsuccessful high-pressure or hightemperature wells. According to international standards, PEMEX achieved excellent exploration results in deepwater during this period.

After the Energy Reform PEMEX shifted its focus from its area of most expertise, the shallow waters of the Southeast Basin, to deepwater areas. Over one-third of the wells drilled over the past three years were in deepwater. These are more expensive wells that take longer to drill. PEMEX had planned to drill many more wells to meet its commitments for the 108 exploration areas it was assigned in Round Zero, but refocused its exploration strategy toward deepwater. At the same time, PEMEX adjusted its strategy by drilling its first exploration well in a new area outside the center of the target to accelerate the exploration process.

Q: How do the farm-outs affect PEMEX’s reserves?

A: The incorporation of reserves depends on the oil price and the time frame within which the reserves can be put into production. In the case of Trion, and all deepwater discoveries, PEMEX incorporated 1P reserves in the immediate area of the well while the majority of reserves that will be certified are 3P reserves quantified based on the oil price. The fact that PEMEX does not have the proven capability to develop deepwater fields led reserves certifiers to assume that PEMEX would not be able to develop its deepwater discoveries in the coming years. As a result, it cannot certify these resources as reserves and instead registers them as contingent resources. In case of a farmout with an experienced partner that has the technological capabilities to develop the field, such as BHP Billiton in case of Trion, these contingent resources can immediately be reclassified as 3P reserves. Therefore, Trion was presented as a field with 3P reserves of 485 million barrels of oil equivalent. The same will happen with the farm-out of the deepwater Nobilis-Maximino block.

Q: What is your perspective on the base and incremental scenario that PEMEX has presented for exploration investment and reserves incorporation?

A: This scenario that assumes that PEMEX will incorporate over 1 billion barrels of oil equivalent, based on the fields and areas assigned to PEMEX during Round One, is optimistic and will need strong support from farm-outs. Based on the first four months of 2017, PEMEX is not on track to achieve this ambitious target. The total volume of 1P crude oil reserves on January 2016 stood at 7.640 barrels and dropped to 7.037 billion barrels on January 1, 2017, a drop of 7.9 percent.


Q: How might the different exploration philosophies employed by private operators influence PEMEX’s strategy?

A: The differentiation between the private operators is based on their know-how, philosophy and exploration and development strategy but they all have to follow the general industry logic of evaluating opportunities, incorporating reserves and delimiting fields. Every operator pursues its objectives differently, meaning that they use different interpretation and drilling approaches and technologies. Another differentiator is how fast these companies want to advance to the production stage. The main objective of certain operators is to gain an optimal understanding of the subsurface and reservoir to optimally develop and manage the reservoir over time, which will maximize the value of the reservoir. Other operators will have the objective of putting discoveries into production as fast as possible to recover their investments.

Q: How has CNH’s responsibility for approving wells changed?

A: There has been a change in the drilling guidelines. In the past, the Ministry of Energy was in charge of authorizing wells. After the Energy Reform, CNH started authorizing all types of wells. The law distinguishes three types of wells: exploratory, deepwater and what are called pozos tipo (well types). From a technical point of view, pozos tipo are unconventional wells and development wells whose design can be replicated after approval of the pozo tipo. CNH publishes all authorized wells at the end of every quarter.

Q: How are CNH and ASEA interacting in the well authorization process and in performance monitoring?

A: We have tried to operate as a “single window” for all permits but we also should be careful to not interfere in the ASEA’s processes. A lot of the information that is provided to us by the operators is passed on to ASEA. We do invite ASEA to our work meetings with the operators to avoid duplication. We work independently but in parallel since operators cannot move forward without authorization from CNH and a favorable opinion from ASEA.

Q: What are your expectations for exploration results and what roles will the different players have?

A: There are areas of opportunity based on the lessons learned by CNH in recent years. One of the great exploration challenges is evaluating Mexico’s hydrocarbon potential, which is CNH’s responsibility. Another priority is ensuring that the new operators are optimizing their exploration plans through the implementation of regulations. We have to take advantage of the new information that is available.

In August, PEMEX will reach the end of the initial three-month exploration period for the 109 areas it was assigned during Round Zero. Our responsibility will be to verify if PEMEX has complied with the minimum work requirements for the remaining 108 areas after the Trion farm-out. This is a great challenge for both PEMEX and CNH because this assessment will decide areas receive a two-year extension. If we want PEMEX to be producing hydrocarbons in the future, it will need exploration areas both as assignments and farm-outs.

The new operators have only recently started their exploration activities and are starting to comply with their minimum work requirements. The main challenge for the operators is to ensure that they are compliant, meaning that they will start to contribute to the development of the exploration in Mexico and are starting to incorporate reserves. This will be the main indicator of the success of the Energy Reform in the short term.