Campaign promises to fund social programs likely to force López Obrador to stay course
By Linda Hsieh, Managing Editor, and Karen Boman, Associate Editor
Mexico’s newly elected president Andrés Manuel López Obrador – who has been an outspoken opponent of the country’s 2013 energy reform that ended PEMEX’s oil sector monopoly – made a statement at a press conference in early August that he will ban hydraulic fracturing in Mexico.
“If such a ban was implemented and includes natural gas production, unconventional gas exploration will go by the wayside, and Mexico will either be forced to import more American gas or seek gas offshore,” said David Goldwyn, Chairman of the Energy Advisory Group and Non-Resident Senior Fellow with the Atlantic Council’s Adrienne Arsht Latin America Center. It remains to be seen, however, whether the president-elect’s statement is just politics or if he will follow through.
Since he picked up more than 50% of the vote to win Mexico’s 1 July presidential election, Mr López Obrador has promised to respect existing contracts, and analysts believe he is unlikely to reverse ongoing reforms in a major way.
Currently, only incremental changes are expected once the new president takes office on 1 December. One change that has already come to pass is a delay in additional licensing rounds in order to give the new administration more time to review license terms.
On 18 July, Mexico’s National Hydro-carbons Commission (CNH) announced it had moved bidding rounds 3.2 and 3.3 and seven farm-outs with PEMEX from the original date of 5 September this year to 14 February 2019. The change came at the request of Mexico’s Ministry of Finance, which was seeking more time to finalize contract terms and to give companies more time to analyze the associated data, according to Óscar Roldán, Head of CNH’s National Data Repository. “It also gives CNH a chance to work hand-in-hand with the federal government’s transition team to review current contracts and adjust future contract terms,” he added.
In 2013, energy reforms approved in Mexico opened the country to investments from private and foreign companies by creating a framework for acreage licensing rounds and by allowing new E&P contract models. These include licenses, production-sharing, profit-sharing and service contracts. Prior to the constitutional reforms, foreign companies could only participate in service contracts where companies were paid for services. They were not allowed shares or profits associated with oil and gas production, according to a 2017 report by the US Energy Information Administration (EIA).
With the populist president soon taking office, however, changes to these reforms are anticipated. In addition to delays in new licensing rounds, local content requirements could also be revised and hinder investments in the process, Mr Goldwyn said.
“The previous administration, under President Enrique Peña Nieto, was very savvy at establishing low local content percentages for deepwater, where Mexico has no domestic competency, and higher in areas where they have secondary services and competency based on their conventional drilling experience.”
It’s also been speculated that the new president might end the PEMEX joint venture (JV) program, which was established in 2014 to provide the NOC with the technology and capital needed to reverse its production declines. The program’s ultimate goal is to increase profits for both the NOC and the national government. “JVs play a central role in mitigating PEMEX’s production decline, but Mr López Obrador has publicly voiced opposition to the JV program. His Mexico-first ideology is likely to take the form of a stronger PEMEX capable of leveraging more advantageous terms in the JV process,” said Maria Cortez, Senior Research Manager with consultancy firm Wood Mackenzie.
While there is a chance the JV program could be pulled, she believes the new administration will show pragmatism once it considers the additional production and revenues that could be generated under the ongoing reforms. In particular, she pointed to pressures that will be exerted on the new government to fund education, youth job training and pensions – all programs that Mr López Obrador proposed during his campaign.
Even if the JV program is left in place, changes to how it’s run may be made, such as allowing PEMEX to choose its own partners. The government currently appoints partners for the NOC after going through a bidding round, but this lack of control for PEMEX has led to its reluctance to participate in farm-outs. As a result, almost no farm-outs were conducted during the first four years of the Peña Nieto administration, Mr Goldwyn said, noting the negative impact this had on PEMEX’s production.
It’s also uncertain how big a role the new government will want PEMEX to play in the country’s oil and gas sector going forward. For example, it might require the NOC to participate in every consortium, or perhaps it will allocate new acreage solely for PEMEX, similar to what was done with Round Zero in August 2014, Mr Goldwyn said. During that licensing round, PEMEX was given the right of first refusal on all acreage offered. PEMEX ended up being awarded the right to develop 83% of Mexico’s proved and probable reserves and 21% of total prospective resources.
Still, Mr López Obrador will face significant constraints in terms of what he can do with PEMEX, regardless of his ambitions. “The factors that drove the energy reform, which were a lack of capital and technological expertise in PEMEX for both deepwater and unconventional production, are unchanged,” Mr Goldwyn said. Moreover, PEMEX’s finances remain under the control of Mexico’s Ministry of Finance, and significant change is unlikely unless PEMEX gets financial autonomy and is able to raise funds on the stock market.
The new president recently announced that he will move ahead with his plan to build a new refinery in the Tabasco region, at a reported cost of $8.6 billion. He is also planning to inject $4 billion into PEMEX for exploration, and additional money for proposed refinery renovations in Mexico’s six existing facilities.
Since the 2013 energy reforms, nine licensing rounds have been held, from Round Zero in 2014 to the shallow-water Round 3.1 in March this year. More than 100 onshore and offshore blocks – including 46 onshore blocks and 58 shallow- and deepwater blocks – have been awarded for E&P.
So far, 16 exploration wells that were committed to under the licensing rounds have been drilled, four are drilling and six are planned for drilling. Companies that have participated have been diverse, from supermajors such as Shell and foreign national oil companies such as Qatar Petroleum to regional independents like BHP Billiton and new Mexican operators like Sierra Oil & Gas. These companies are bringing not only additional capital to fund new E&P projects but also a wide range of technical expertise that Mexico sorely needs.
Wood Mackenzie attributed the success of Mexico’s recent licensing rounds to the creation of a fiscal regime with reasonable minimum bids. These have allowed the country to compete internationally.
At the same time, the government has been able to establish progressive factors in the contracts, such as with the contractual oil price, R-factors for statistical modeling, and internal rate of return adjustment mechanisms, that will maximize value for the country. Further, the country has smartly set lower minimums for less prospective acreage; this has facilitated the award of marginal blocks that could yield important discoveries, according to a May 2018 report from Wood Mackenzie.
Over the next four years, 63 exploration and appraisal wells – evenly split between deepwater and shallow water – have been committed for drilling as part of the licensing rounds. If all of these wells are drilled, they would represent a total spend of $5 billion for deepwater and $2.5 billion for shallow water. Wood Mackenzie estimates the 63 wells could yield up to 20 discoveries, assuming they are primarily exploration wells and have a success rate of approximately 30%, the global average for frontier plays.
Wood Mackenzie also estimates that, by 2024, investment from Round One, which includes several shallow-water projects and one deepwater project, will contribute approximately 500,000 BOE to Mexico’s overall production. That growth will be driven partly by Eni’s Amoca-2 and Talos Energy’s Zama-1 discoveries. Both are located in the Salinas-Sureste Basin in southeast Mexico, which includes several sub-basins from onshore to ultra-deepwater.
The Amoca-2 exploration well, drilled in March 2017, was the first well drilled following the energy reform’s passage. It was drilled to a total depth of 3,500 m and encountered approximately 110 m of net oil pay from several Pliocene reservoir sandstones. Amoca-2 is located in Contractual Area 1, 1,200 km west of Ciudad del Carmen, in Campeche Bay in 25 m of water.
Eni currently is drilling the Amoca-3 appraisal well on the Amoca field, where production is expected to begin in the second half of 2019. Wholly owned and operated by Eni, Amoca is likely to be the first greenfield project to come on-stream following passage of Mexico’s energy reform.
Talos’ Zama-1 discovery is also expected to contribute significantly to Mexico’s production growth in the coming years. Drilled by the ENSCO 8503 semisubmersible in 546 ft of water, Zama-1 struck a contiguous gross oil-bearing interval of more than 1,100 ft – with up to 650 ft of net oil-bearing reservoir in the Upper Miocene sandstone reservoirs. It yielded one of the world’s largest shallow-water finds in the past 20 years, estimated to hold 600 million bbl of commercial reserves.
In Q4 2018, Talos plans to start appraising the Zama field using the Ensco 8503. During the appraisal campaign – in which Talos must drill at least three boreholes and conduct a drill stem test and extensive coring and reservoir fluid sampling – the company plans to deepen one wellbore to test the Marte prospect. Once a front-end engineering design study is completed and a unitization agreement is reached, Talos expects to announce the final investment decision in Q4 2019 or Q1 2020.
The company has been in discussions with Mexico’s Energy Ministry to unitize efforts to develop Zama, whose reserves extend into another block held by PEMEX. Production is expected to begin in 2022 and increase through 2024 as additional field facilities are added, Talos announced in May. Ensco is in discussions with operators for more drilling work offshore Mexico and is participating in rig tenders with PEMEX and IOCs for midwater floaters and jackups for exploration and appraisal work in 2019 and beyond, said Gilles Luca, Senior VP Western Hemisphere for Ensco. “Right now it’s mostly exploration programs and a bit of appraisal work, but because of the high success rate we’ve seen in the new acreage, you would expect some development programs to commence down the road,” he said.
The drilling contractor had operated jackups in Mexico nearly continuously from 2008 to 2016, which provided valuable experience as Ensco navigated regulations in the country’s reformed energy sector since 2013. “Our knowledge in starting operations in the region is proving extremely beneficial and allows international operators who may not have had experience working in Mexico the ability to leverage our experience,” Mr Luca said.
He added that staying agile when dealing with new regulations and new regulatory bodies in the country has also helped to keep the process manageable. “The reform, from the standpoint of local content, was very realistic and didn’t pose constraints that slowed our work down,” he noted.
Lessons have also been learned around the management of logistical support for materials, boats and helicopters. Mexico’s offshore support logistics industry is undergoing a transition as they are now partners with new entrants into the market, Mr Luca said.
Mexico’s shale development faces challenges
Although efforts to develop Mexico’s unconventional resources have remained scarce so far, this sector of the market could shift into higher gear under the new administration. There is worry in Mexico that US President Donald Trump could disrupt US natural gas exports to Mexico to try and influence NAFTA negotiations, Mr Goldwyn with the Atlantic Council said. This could lead the Mexican president to push PEMEX or other Mexican-based operators to invest in shale developments in order to boost natural gas production. In 2017, the US exported 4.6 billion cu ft/day of natural gas to Mexico via pipeline or liquefied natural gas cargoes, according to the EIA.
It’s difficult to say whether Mr López Obrador will follow through with his vow to ban hydraulic fracturing, said Samantha Gross, Fellow in Foreign Policy focused on energy and climate issues with the Brookings Institution. Once the president-elect sees the “cold hard reality” of what a fracking ban and other changes to Mexico’s energy regulations could mean, he could change his mind. Ms Gross believes the energy reform is good for Mexico and Mexicans but is scratching her head over the president-elect’s statements on energy reform and what they could ultimately mean for the country.
Two bidding rounds – 3.2 and 3.3 – are currently scheduled for early 2019. The former offers 37 onshore conventional blocks and the latter offers nine onshore unconventional blocks. Round 3.3 will offer companies a chance to bid on nine licenses that touch the Pimienta formation of the Upper Jurassic unconventional play, which CNH considers one of the most attractive areas of Mexico for future gas, wet gas and oil production. Companies also will be able to bid on seven farm-out opportunities with PEMEX, covering 4,500 sq km of acreage with 2P and 3P reserves and a mix of historical production and newer, unexplored fields.
Wood Mackenzie sees challenges to the development of Mexico’s onshore unconventional oil and gas, however. Mexico does have spare onshore drilling capacity, but developing Mexico’s shale resources will require the import of higher-spec rigs to drill and complete wells 3,000 m deep, as well as hydraulic fracturing equipment. “We expect this will be a difficult undertaking for two reasons. First, service companies will need to sort out logistical challenges of operating in Mexico, likely a process which will dampen interest for smaller companies,” Ms Cortez explained.
Second, the 2018 uptick in activity in the Permian Basin has depleted some of the excess capacity of rigs from the downturn. Rig rates in North America – estimated at $20,000/day to $25,000/day – and demand for pressure-pumping equipment also have tightened. “We would expect early Mexico shale developers to compete head to head with US market share, while also paying the premium for crossing the border. They will need to sort out the logistical challenges associated with importing equipment, staging it and storing it. We believe service companies will not be incentivized to do this without seeing a significant uptick in activity,” Ms Cortez explained.
Resourcing water is another increasingly important factor for cost competitiveness in shale. “Sourcing sufficient volumes will be key to any large-scale shale development,” Ms Cortez said. “The northern region of Mexico is arid. Surface water rights in the northern basins are already allocated between industrial and agricultural users so finding sources will be difficult.”
Ensuring safety and security in the region against gang-related crime and violence will likely be the biggest challenge these companies face for unconventional and conventional plays and will likely narrow the playing field of E&P and service companies. “Locally incentivizing governments to improve security in oilfields will greatly increase the odds of development, as will demonstrating tangible local benefits,” Ms Cortez said.
The northern Mexico state of Tamaulipas, through a joint venture of local industry and state government, has sought to educate the local community on the benefits shale can have on the local economy. “They have the advantage that shale is just across the border with the US, so the concept and story of shale is not foreign to Mexicans,” Ms Cortez noted. DC