PEMEX to Boost Production Through PartnershipsWed, 01/20/2016 - 14:46
Q: What are your responsibilities of the Prospective Resources, Reserves, and Associations division at PEMEX, and how do these differ from PEMEX Alliances & New Business?
A: PEMEX E&P was reorganized into three areas. One division is dedicated to exploration, discovering new prospective resources. On the production side, one division will manage the development of existing fields. However, a third area will focus on fields where third parties are involved in the production process. The reason this third division was created is that the E&P divisions have plenty of work on their plate, and managing partnerships requires different skills and approaches than only working within PEMEX. That being said, alliances, partnerships, and joint ventures fall under the responsibility of the Prospective Resources, Reserves, and Associations division, and the teams that work in fields under a JV will report to this division. While CNH will define our partners through a bidding process, we have to decide who the operator will be. If PEMEX is going to operate, then PEMEX E&P will be responsible for the project because technical details and the allocation of CAPEX fall on the operator’s side.
The main difference between the Prospective Resources, Reserves, and Associations division of PEMEX E&P and the corporate division Alliances and New Business is that the latter is in charge of defining the alliances that will maximize PEMEX’s performance, define the people who will be members of the board in a JV, and decide which role PEMEX people will play in each case. On the other hand, Prospective Resources, Reserves, and Associations will focus on technical aspects and on the actual production processes. In this sense, my area deals with associations in existing contracts, such as the migration of CIEPS and COPS, and future partnerships, such as farm-outs. In addition, we are responsible for validating discovered volumes and certifying hydrocarbon reserves according to CNH’s guidelines and our internal procedures.
Q: What has been holding back the process of the migration of CIEPS and COPS?
A: Some service contracts that were signed under a bidding process prior to the reform can be transferred to E&P contracts under the new framework, and at the moment there are 16 CIEPS and six COPS looking to be migrated into the new scheme. Initially, we split these contracts into two sets of 11. The first set of migrating contracts consisted of COPS that have existed since 2003-2004 and some CIEPS that were signed in 2011, such as Santuario, Magallanes, Pánuco, Arenque, Altamira, San Andrés, Ebano, Nejo, Misión, and Olmos. The second set was composed of Tierra Blanca, Carrizo, and the last five Chicontepec blocks, Amatitlán, Miahuapan, Pitepec, Humapa, and Soledad, as well as other four COPS like Cuervito, Fronterizo, Monclova, and Pirineo. Although Miquetla belongs to the second set, it was included in the first due to a request from the company operating it.
There are 22 blocks and each entails a different learning process. When we submitted the initial request to migrate the contracts, there was a need to make some amendments to the entitlement blocks that were awarded to PEMEX in Round Zero, such as modifying the entitlement to include the whole block. In other cases, some assigned areas overlapped, which we noticed when we began the process and had to request the correction. In the meantime, the Ministry of Energy and CNH issued new guidelines for E&P plans that were not considered when the Round Zero fields were awarded.
To start the process, PEMEX had to sign a letter of consent with its future partners, and then undergo a financial assessment, as each party will have its own working interests, so we had to establish the shares. Also, changing the type of contract entails demonstrating to the Ministry of Finance that the migration will improve government take, increase reserves, and increase production by decreasing the fiscal obligations. Part of the negotiation process included carefully defining reserves, area extension, facilities, infrastructure, and royalties. For this purpose, we hired five international financial entities that used different methodologies, which were aligned and standardized at the end of the process. The next step was to summarize the development and production plans, as well as the minimum work commitment that will be included in the new E&P contracts. It was a long discussion because with the cost recovery at 70% and sometimes 100% of eligible costs. We went to the basics determining what eligibility meant and what was an eligible cost. After this learning process, I can assure you that all the service contracts, except for the ones in blocks with a pending amparo will be migrated.
We started with Santuario operated by Petrofac, Misión operated by Techpetrol, Ébano, and Miquetla, operated by Grupo Diavaz. Companies have already submitted their requests before the Ministry of Energy and ten contracts have received a green light. Olmos, a COPF for a gas field in the northern region, cannot be moved further because of an amparo from a mining company. We have talked about this with Lewis Energy, the company requesting the migration, who understands that not much can be done at the moment. As for the rest of the blocks, we decided to move on different fronts but we found that all the players in the process, the Ministry of Energy, the Ministry of Finance, CNH, and PEMEX, needed to learn a new process. In the past, every actor tried to advance in the best direction, and these were not always fully aligned, but now we have assembled a task force that includes a legal counsel, New Business, Associations, the finance area, and many others in order to align and streamline the process. Santuario is close to being successfully migrated, and all the CIEPS and COPS should be migrated before the end of this year.
Q: What are the overall production trends, and what context does this create for the attractiveness of COPS, CIEPS, and additional future partnerships?
A: PEMEX’s total production reached 3.383 million b/d in 2004, but has dropped to 2.259 million b/d in 2016. Since 2004, when production at Cantarell peaked at 2.125 million b/d, an extended decline reduced this field’s production to 230,000b/d by March 2016. However, the other fields in PEMEX’s portfolio have experienced an overall production increase as a result of our effective diversification strategy that compensated a substantial proportion of Cantarell’s production decline. Compensating the production decline of a super-giant field and increasing production by 60% is something no other company in the world has done. The challenge remains, but the numbers herald good news.
In terms of annual averages, the 15 entitlements in Samaria Luna contributed with 142,000b/d, Bellota-Jujo produced 96,000b/d across 26 fields, Cinco Presidentes 88,000b/d in 21 fields, and Macuspana-Muspac produced57,000 b/d across 37 fields. Poza Rica was able to produce 57,000b/d in its 60 fields, while ATG (Chicontepec) produced 41,000 in 28 fields. The Veracruz asset yielded 14,000b/d, and Burgos is not producing oil at the moment. In the group of fields with contracts awaiting migration, Ébano is the largest oil producer, with 11,000b/d, Santuario produces 5,000b/d, Arenque 4,000b/d, and 6,000b/d came from OgarrioSánchez Magallanes. In the case of offshore assets, Litoral de Tabasco is responsible for 363,000b/d, including the Tsimin-Xux field. Abtakún-Pol-Chuc produced 200,000b/d across 16 fields, and the eight fields in Ku-Maloob-Zaap produced 860,000b/d. Cantarell produced 232,000b/d with its ten fields. While some fields like Samaria Luna are declining, other like Abkatún-Pol-Chuc, Litoral de Tabasco, and even Ku-Maloob-Zaap are yielding positive results. Highly productive new fields were discovered in Abkatún, such as Onel, Kuil, Homol, and Chuhuc, which are helping us counter the decline rate. In the Cantarell complex, Ixtoc and Kambesah produced 15,000b/d, Ek-Balam 46,000b/d, and Chac, Kutz, Nohoch, and Takin contributed with 27,000b/d. Sihil had an output of 31,000b/d, but the most important producer in Cantarell was Akal with 78,000b/d. If we only focus on the scope of the farm-outs, Cárdenas, Mora, and Samaria produced 48,000b/d, Ek-Balam 46,000b/d, and Bolontiku-Sinan had an output of 43,000b/d. Ogarrio yielded 10,000b/d and Rodador 3,000b/d. Ayatsil-Tekel produced 3,000b/d, which is not bad considering the asset has recently started production.
Regarding gas production, the largest output came from Cantarell in the 2007-2008 period, which amounted to 1bcf of formation gas. Cantarell now produces 10% of the total gas production. There are considerable natural gas producers, such as Ogarrio, which produced 33mcf/d. Rodador is not a gas producer, but it had an output of 5mcf/d of associated gas. Nejo is worth mentioning, as it produces 200mcf/d. Back in 2013, we began reporting Nejo’s production as condensates, but now it is reporting liquids. Cuervito and Fornterizo have an output of 15mcf/d, and we are in talks with the operators, Grupo Diavaz, Petrobras, and Teikoku because even though the production is significant, we want to make sure it is profitable under the current regime. In the exclusive case of CIEPS and COPS, the former produce 273mcf/d, a higher number than that of the COPS, which are natural gas producing assets and have an output of 147mcf/d.
At their peak in 2009, Monclova produced 1bcf, making it an important asset. Burgos produced 90mcf/d, Nejo 80mcf/d, and Misión 1.1bcf/d. There are significant gas producers but it is important to take the Henry Hub price reference for future estimates. If we find a great production potential, we could allocate CAPEX and get some fields to the production levels they experienced back in 2009-2011.