2021 – a year of rebound

For most living through it, the ongoing pandemic has seemingly melded 2020 and 2021 into a single continuum, one day or year indistinguishable from the next except for the now famous euphemisms of ‘pre-Covid’ and ‘post-Covid’. But if we apply a critical lens and look closely many in the energy space will look back fondly on what was the previous 11 months. 

In fact, 2021 stands firmly on its own two legs as a year of rebound. We’ve seen a price rally for Brent that has allowed it to more than double since the beginning of the year, as demand recovers and supply stays (artificially) tight. The Latin America region has also seen its fair share of success stories in 2021. Vaca Muerta production keeps delivering, sanctioning activity remains high in Guyana and Chile continues to take the forefront in energy transition and renewable investments.  

Argentina’s swelling production from the Vaca Muerta is a sign of its maturation as an international shale play. Outside of the United States shale development has been quite difficult for a myriad of reasons but particularly painful has been the lack of existing infrastructure. Unconventional plays like the Eagleford or the Wolfcamp benefited from the fact that there has been a large oil industry in place for decades exploiting the very reservoirs that the shale rock beneath was supplying. Operators in the Neuquen basin have had to forge their own path in that sense. And yet the play keeps pushing to new production highs which seem apt to continue in the new year.

Guyana is another area that 2021 has treated well. Aside from several nice discoveries that continue to push reserve estimates higher for the Caribbean country there has also been a heavy emphasis on putting those discovered barrels into production. As Exxon and their partners continue to work with the Government of Guyana to implement and approve development plans for the discovered resources there will be more work to be allocated to various components of the OFS supply chain. Count on this expenditure to continue through to next year and well beyond.  

The year that was may not get all the credit it is due in terms of recovery and a general turn around in trajectory, certainly the specter of 2020 still looms large. But for Latin America at least the year has signaled stability and resilience, an auspicious start for 2022.  

Todo lo mejor,
Houston, Texas
November 23, 2021

W. Schreiner Parker
Senior Vice President and 
Head of Latin America

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Vaca Muerta oil output tops 175,000 bpd, pushing national total to six-year high

Argentina’s oil output in September has breached past its pre-Covid-19 level to an average of 532,000 barrels per day (bpd), the highest since January 2016, driven by rapid expansions in the oil window of the massive Vaca Muerta shale play. And ongoing oilfield activity in the region is positioning the country for continuous sequential growth through 2022, according to Rystad Energy’s analysis. As discussed in our previous Vaca Muerta update, strong put-on-production (POP) activity in the basin’s oil window has triggered a new phase of accelerated production growth. With 54 horizontal POPs in the oil window in the third quarter, a continuous oil stream expansion in the final three months of the year is inevitable, as many wells were still in the early stages of flowback as of September. The Vaca Muerta pay delivered a staggering sequential increase of 10% in oil output in September, reaching a record high of 174,000 bpd. That implies a 57% growth on a year-over-year basis. Meanwhile, gross gas output flatlined at around 1.56 billion cubic feet per day (Bcfd) as a seasonal demand slowdown starts and this year will again see some gas production curtailments implemented in several major blocks. The latest outlook comes on the back of complete reporting of oil & gas production data for September in Argentina.

Vaca Muerta’s oil output growth between August and September 2021 was primarily driven by new projects in YPF’s LA AMARGA CHICA and BANDURRA SUR blocks. Shell and ExxonMobil were the two other major contributors – with new developments in Shell’s CRUZ DE LORENA and BAJO DEL CHOIQUE operations for ExxonMobil.

On the gas production side, there’s a divergence in the trend of the two major producers, between August and September. TecPetrol’s gas output seemingly peaked at 560 million cubic feet per day (MMcfd) this season in August, declining to 530 MMcfd in September. Meanwhile, YPF was still able to push gas production upwards in September, from 516 MMcfd to 526 MMcfd, thanks to contributions from its associated gas stream in oil blocks, which drove the expansion in liquids production.

TechnipFMC reels in a big Yellowtail fish – just how large is it?

Subsea giant TechnipFMC landed this month a major subsea equipment deal for ExxonMobil’s next phase of the Stabroek development offshore Guyana. The work scope includes as much as 51 enhanced vertical deepwater trees and 12 manifolds, together with associated controls and tie-in equipment. TechnipFMC defines the Yellowtail contract as large, meaning worth between $500 million and $1 billion. The latest subsea job is set eclipse previous Stabroek phases, according to Rystad Energy analysis, and even ranks among the top 10 global contracts so far this century.

TechnipFMC’s giant Payara win last fall, landed the company a contract to supply 41 enhanced vertical deepwater trees to ExxonMobil’s third phase of the Stabroek development off Guyana. The 41-tree deal was – at that time – the largest subsea tree contract handed out since Aker Solutions landed Kaombo in 2014. TechnipFMC’s contract even partly saved the subsea market from awarding fewer than 100 trees in 2020 – something seen only once this century in 2016. Thus, TechnipFMC has a strong bond with ExxonMobil in Guyana, having secured all previous phases of the Stabroek development, as seen from  the figure below. This subsea adventure started back in 2017 when the 17 subsea trees for Liza’s phase 1 were handed out and followed up with an additional 30 subsea trees for Liza phase 2 in 2018. Now – if Yellowtail formally moves ahead – TechnipFMC would have secured almost 140 subsea trees for the Stabroek development alone. This is significant for a subsea market that saw around 140 subsea trees awarded globally last year.

The contract for ExxonMobil’s next phase of the Stabroek development offshore Guyana is subject to final project sanctioning and government approvals.

Chile tops South America’s renewable investment league table

Chile’s aspiration to decarbonize by 2050, combined with ambitious climate and energy policies and a stable investment regime, means it has quickly become South America’s leading nation in the energy transition race. Alongside a bold hydrogen strategy that will see 25 Gigawatts (GW) of electrolyzer capacity installed by 2030, Chile is leveraging its abundant solar and wind resources to boost the share of renewables in power generation by 2030 and phasing out coal power use entirely by 2040. While laudable, the policies present a number of logistical challenges for the South American nation, not least the fact that optimal renewable resources are located in the north and south of the country while most major demand nodes are the center. It means significant investment in transmission lines and energy storage will be required in the years ahead. Rystad Energy analysis shows that, as a result of technology cost reductions and supportive policies, solar will account for over 50% of Chile’s generation capacity by 2050 followed by wind at nearly 20%.

Chilean energy mix: a rollercoaster ride
Chile is among South America’s largest economies with nearly 20 million inhabitants and annual GDP of over US$250 billion. It has a free-market economy that is recognized as one of the most robust in South America. In 2019, Chile ranked 33^rd in the World Economic Forum’s Global Competitiveness Report and in 2010, following a decade of economic progress, became the first South American country to join the Organization for Economic Co-operation and Development (OECD). In the energy space, Chile is Latin America’s new renewable energy champion, overtaking Brazil and Mexico in attracting high levels of foreign direct investment into the sector. Smart and stable energy policy lies behind this success. Recognizing both the risks posed by climate change and the opportunities afforded by addressing the challenges, Chile announced three ambitious energy and climate policies in 2019: reaching carbon neutrality by 2050, phasing out coal-fired generation by 2040, and increasing the share of renewable energy in its electricity mix to 70% by 2030, instead of 2050 as originally planned.

Accelerating the phase-out of coal generation is a milestone in Chile’s changing energy mix which has seen many twists and turns over the past 20 years. Chile has struggled to achieve a reliable energy mix for decades. In the 1980s, it relied heavily on power from hydro resources. However, in the mid-1990s, a combination of continued rapid growth in energy demand driven by economic development, increasing environmental concerns regarding large hydro, and the unreliability of hydropower due to droughts, prompted the government to diversify energy supply by importing natural gas from Argentina.

The low cost of imported natural gas made combined-cycle plants attractive compared to large hydro plants and coal. As a consequence, the sector invested heavily in new gas infrastructure, building four pipelines from Argentina, new gas distribution networks and half a dozen new combined-cycle gas-fired plants at a total cost of around US$4 billion. In 2004, natural gas accounted for 26% of Chile´s total primary energy consumption of which 80-90% came from Argentinean gas suppliers. In 2004-07, Chile’s sole gas supplier Argentina faced an energy crisis and restricted gas exports. As a result, gas supply to Chile fell significantly in 2007 with the fuel’s share of power generation falling 60%. To make things worse, Chile had a drought in 2007-08 in the central south region, which reduced hydropower supply by 20%. As a short-term remedy, oil was largely used to fill the gap with oil-fired generation rising more than five-fold from 2006 to 2007. Later, oil was replaced by a combination of coal-fired generation and, after the commissioning of two liquefied natural gas (LNG) regasification plants, gas imported from other countries. Between 2002 and 2008, Chile’s total CO2 emissions from power generation increased by 77%.