The Mexico energy market has been a hot topic ever since late 2013 when the government decided to liberalize the energy sector, opening it up to foreign investment.
The reform provides an unprecedented opportunity for international companies to participate in development of the nation’s vast oil resources as PEMEX unwinds its current monopoly. Multiple other opportunities exist in the power sector, in renewables development and in the natural gas pipeline sector.
The energy reforms were largely a result of the steep decline of the country’s oil production, inadequate financial resources to turn production around and an inability of PEMEX to keep pace with the technological change taking place in the industry.
Mexico ranks sixth in the world for non-conventional oil and gas resources, right behind Canada and Algeria, but lacks the financial resources to develop its reserves. It would take US$20 billion to extract the country’s reserves over a 210-year period and $87 billion to do it in 50 years. It also would not be possible to do this with one state-owned exploration and production monopoly — this is why the reforms were necessary.
However, private investment cannot come quickly enough. Active drilling rigs in Mexico fell to 43 in February, down 43% from a year prior. Developmental rigs fell to 35 in February, down 44% from February 2015. The biggest year-on-year declines came from the Southern Region (down 15.7 rigs; 52%) and the Southwestern Marine Region (down 12.4 rigs; 56%).
In March, Pemex’s announced a $5.5 billion budget cut, and active rigs plummeted another 43%, while developmental rigs dropped to only 21. The Southern region again was hit hardest, with developmental rigs falling to seven during the month, down 55% from January.
Petroleum production is a major concern for the country, but renewables also are an important focus of the reforms. On top of having significantly large oil and gas resources, Mexico also has significant resources for renewable energy such as geothermal, wind and solar. It is estimated that current renewables generation, plus proven additional renewable resources in the country, could boost generation from renewables from 3.9% of the country’s total power generation to 9.89%.
Adding possible renewable resources to the mix could satisfy the country’s total generation needs, according to Mario Gabriel Budebo, director general of the EXI Fund: Energy and Infrastructure and former independent director of gas and basic petrochemicals at PEMEX. Budebo, who was the keynote speaker at the Platts Global Power Conference in Las Vegas in early April, also noted that significant infrastructure would need to be built to support such a major turn to renewables, highlighting the significant need for private investment to support the renewables efforts. He also gave a firsthand account of the Mexican energy landscape and the other investment opportunities the reform provides for international companies.
Investment in pipeline infrastructure also is a major need throughout the country. Just a few years ago, only 10 states had natural gas pipelines, but today 22 states have them. The Ministry of Energy estimates US$10.1 billion needs to be invested in pipeline infrastructure between 2015 and 2019 to build 3,205 miles of new pipeline, which would increase the total pipeline network to 11,081 miles.
While the country waits for the benefits of private investment in exploration and production, most of its natural gas supply to feed all the new gas pipeline and power generation infrastructure will originate in the United States. In its new Mexico Energy Monthly report, Platts Analytics said US natural gas exports to Mexico rose to more than 3.5 Bcf/d in April, prompted by a near 0.7 Bcf/d year-on-year increase in gas demand from the Mexican power sector. Greater reliance on US gas supply has reduced the need for more expensive imported liquefied natural gas. LNG imports by Mexico, despite rising to about 0.6 Bcf/d in April, were down 0.2 Bcf/d from April 2015 levels. Total non-US gas supply in Mexico was down 0.3 Bcf/d in April compared to April 2015.
Platts Analytics expects that US natural gas exports to Mexico could break above 4 Bcf/d by early summer as demand picks up and domestic supply continues to decline due to a lack of drilling activity.
Power demand is expected to increase as the country transitions to greater reliance on gas-fired generation and retires as much as 2.1 GW of fuel oil-generation plants over the next year.
However, lingering gas pipeline transportation constraints on both the north-to-south corridors (Los Ramones Phase II South) and the east-to-west corridors (El Enino – Topolobampo), may hinder exports this summer if planned pipeline expansions miss their expected in-service dates, in which case Mexico would likely increase reliance on LNG imports.
Mexico’s energy infrastructure development is behind other emerging economies, creating significant investment opportunities for both domestic and foreign companies.
By Anne Swedberg, Manager, Gas and Power Analytics
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Headline crude prices for the week beginning 12 August 2019 – Brent: US$58/b; WTI: US$54/b
Headlines of the week
The momentum for crude prices abated in the second quarter of 2019, providing less cushion for the financial results of the world’s oil companies. But while still profitable, the less-than-ideal crude prices led to mixed results across the boards – exposing gaps and pressure points for individual firms masked by stronger prices in Q119.
In a preview of general performance in the industry, Total – traditionally the first of the supermajors to release its earnings – announced results that fell short of expectations. Net profits for the French firm fell to US$2.89 billion from US$3.55 billion, below analyst predictions. This was despite a 9% increase in oil and gas production – in particularly increases in LNG sales – and a softer 2.5% drop in revenue. Total also announced that it would be selling off US$5 billion in assets through 2020 to keep a lid on debt after agreeing to purchase Anadarko Petroleum’s African assets for US$8.8 billion through Occidental.
As with Total, weaker crude prices were the common factor in Q219 results in the industry, though the exact extent differed. Russia’s Gazprom posted higher revenue and higher net profits, while Norway’s Equinor reported falls in both revenue and net profits – leading it to slash investment plans for the year. American producer ConocoPhillips’ quarterly profits and revenue were flat year-on-year, while Italy’s Eni – which has seen major success in Africa – reported flat revenue but lower profits.
After several quarters of disappointing analysts, ExxonMobil managed to beat expectations in Q219 – recording better-than-expected net profits of US$3.1 billion. In comparison, Shell – which has outperformed ExxonMobil over the past few reporting periods – disappointed the market with net profits halving to US$3 billion from US$6 billion in Q218. The weak performance was attributed (once again) to lower crude prices, as well as lower refining margins. BP, however, managed to beat expectations with net profits of US$2.8 billion, on par with its performance in Q218. But the supermajor king of the quarter was Chevron, with net profits of US$4.3 billion from gains in Permian production, as well as the termination fee from Anadarko after the latter walked away from a buyout deal in favour of Occidental.
And then, there was a surprise. In a rare move, Saudi Aramco – long reputed to be the world’s largest and most profitable energy firm – published its earnings report for 1H19, which is its first ever. The results confirmed what the industry had long accepted as fact: net profit was US$46.9 billion. If split evenly, Aramco’s net profits would be more than the five supermajors combined in Q219. Interestingly, Aramco also divulged that it had paid out US$46.4 billion in dividends, or 99% of its net profit. US$20 billion of that dividend was paid to its principle shareholder – the government of Saudi Arabia – up from US$6 billion in 1H18, which makes for interesting reading to potential investors as Aramco makes a second push for an IPO. With Saudi Aramco CFO Khalid al-Dabbagh announcing that the company was ‘ready for the IPO’ during its first ever earnings call, this reporting paves the way to the behemoth opening up its shares to the public. But all the deep reservoirs in the world did not shield Aramco from market forces. As it led the way in adhering to the OPEC+ club’s current supply restrictions, weaker crude prices saw net profit fall by 11.5% from US$53 billion a year earlier.
So, it’s been a mixed bunch of results this quarter – which perhaps showcases the differences in operational strategies of the world’s oil and gas companies. There is no danger of financials heading into the red any time soon, but without a rising tide of crude prices, Q219 simply shows that though the challenges facing the industry are the same, their approaches to the solutions still differ.
Supermajor Financials: Q2 2019
Source: U.S. Energy Information Administration, CEDIGAZ, Global Trade Tracker
Australia is on track to surpass Qatar as the world’s largest liquefied natural gas (LNG) exporter, according to Australia’s Department of Industry, Innovation, and Science (DIIS). Australia already surpasses Qatar in LNG export capacity and exported more LNG than Qatar in November 2018 and April 2019. Within the next year, as Australia’s newly commissioned projects ramp up and operate at full capacity, EIA expects Australia to consistently export more LNG than Qatar.
Australia’s LNG export capacity increased from 2.6 billion cubic feet per day (Bcf/d) in 2011 to more than 11.4 Bcf/d in 2019. Australia’s DIIS forecasts that Australian LNG exports will grow to 10.8 Bcf/d by 2020–21 once the recently commissioned Wheatstone, Ichthys, and Prelude floating LNG (FLNG) projects ramp up to full production. Prelude FLNG, a barge located offshore in northwestern Australia, was the last of the eight new LNG export projects that came online in Australia in 2012 through 2018 as part of a major LNG capacity buildout.
Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL), trade press
Note: Project’s online date reflects shipment of the first LNG cargo. North West Shelf Trains 1–2 have been in operation since 1989, Train 3 since 1992, Train 4 since 2004, and Train 5 since 2008.
Starting in 2012, five LNG export projects were developed in northwestern Australia: onshore projects Pluto, Gorgon, Wheatstone, and Ichthys, and the offshore Prelude FLNG. The total LNG export capacity in northwestern Australia is now 8.1 Bcf/d. In eastern Australia, three LNG export projects were completed in 2015 and 2016 on Curtis Island in Queensland—Queensland Curtis, Gladstone, and Australia Pacific—with a combined nameplate capacity of 3.4 Bcf/d. All three projects in eastern Australia use natural gas from coalbed methane as a feedstock to produce LNG.
Source: U.S. Energy Information Administration
Most of Australia’s LNG is exported under long-term contracts to three countries: Japan, China, and South Korea. An increasing share of Australia’s LNG exports in recent years has been sent to China to serve its growing natural gas demand. The remaining volumes were almost entirely exported to other countries in Asia, with occasional small volumes exported to destinations outside of Asia.
Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL)
For several years, Australia’s natural gas markets in eastern states have been experiencing natural gas shortages and increasing prices because coal-bed methane production at some LNG export facilities in Queensland has not been meeting LNG export commitments. During these shortfalls, project developers have been supplementing their own production with natural gas purchased from the domestic market. The Australian government implemented several initiatives to address domestic natural gas production shortages in eastern states.
Several private companies proposed to develop LNG import terminals in southeastern Australia. Of the five proposed LNG import projects, Port Kembla LNG (proposed import capacity of 0.3 Bcf/d) is in the most advanced stage, having secured the necessary siting permits and an offtake contract with Australian customers. If built, the Port Kembla project will use the floating storage and regasification unit (FSRU) Höegh Galleon starting in January 2021.