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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Source: U.S. Energy Information Administration, Short-Term Energy Outlook
In April 2019, Venezuela's crude oil production averaged 830,000 barrels per day (b/d), down from 1.2 million b/d at the beginning of the year, according to EIA’s May 2019 Short-Term Energy Outlook. This average is the lowest level since January 2003, when a nationwide strike and civil unrest largely brought the operations of Venezuela's state oil company, Petróleos de Venezuela, S.A. (PdVSA), to a halt. Widespread power outages, mismanagement of the country's oil industry, and U.S. sanctions directed at Venezuela's energy sector and PdVSA have all contributed to the recent declines.
Source: U.S. Energy Information Administration, based on Baker Hughes
Venezuela’s oil production has decreased significantly over the last three years. Production declines accelerated in 2018, decreasing by an average of 33,000 b/d each month in 2018, and the rate of decline increased to an average of over 135,000 b/d per month in the first quarter of 2019. The number of active oil rigs—an indicator of future oil production—also fell from nearly 70 rigs in the first quarter of 2016 to 24 rigs in the first quarter of 2019. The declines in Venezuelan crude oil production will have limited effects on the United States, as U.S. imports of Venezuelan crude oil have decreased over the last several years. EIA estimates that U.S. crude oil imports from Venezuela in 2018 averaged 505,000 b/d and were the lowest since 1989.
EIA expects Venezuela's crude oil production to continue decreasing in 2019, and declines may accelerate as sanctions-related deadlines pass. These deadlines include provisions that third-party entities using the U.S. financial system stop transactions with PdVSA by April 28 and that U.S. companies, including oil service companies, involved in the oil sector must cease operations in Venezuela by July 27. Venezuela's chronic shortage of workers across the industry and the departure of U.S. oilfield service companies, among other factors, will contribute to a further decrease in production.
Additionally, U.S. sanctions, as outlined in the January 25, 2019 Executive Order 13857, immediately banned U.S. exports of petroleum products—including unfinished oils that are blended with Venezuela's heavy crude oil for processing—to Venezuela. The Executive Order also required payments for PdVSA-owned petroleum and petroleum products to be placed into an escrow account inaccessible by the company. Preliminary weekly estimates indicate a significant decline in U.S. crude oil imports from Venezuela in February and March, as without direct access to cash payments, PdVSA had little reason to export crude oil to the United States.
India, China, and some European countries continued to receive Venezuela's crude oil, according to data published by ClipperData Inc. Venezuela is likely keeping some crude oil cargoes intended for exports in floating storageuntil it finds buyers for the cargoes.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook, and Clipper Data Inc.
A series of ongoing nationwide power outages in Venezuela that began on March 7 cut electricity to the country's oil-producing areas, likely damaging the reservoirs and associated infrastructure. In the Orinoco Oil Belt area, Venezuela produces extra-heavy crude oil that requires dilution with condensate or other light oils before the oil is sent by pipeline to domestic refineries or export terminals. Venezuela’s upgraders, complex processing units that upgrade the extra-heavy crude oil to help facilitate transport, were shut down in March during the power outages.
If Venezuelan crude or upgraded oil cannot flow as a result of a lack of power to the pumping infrastructure, heavier molecules sink and form a tar-like layer in the pipelines that can hinder the flow from resuming even after the power outages are resolved. However, according to tanker tracking data, Venezuela's main export terminal at Puerto José was apparently able to load crude oil onto vessels between power outages, possibly indicating that the loaded crude oil was taken from onshore storage. For this reason, EIA estimates that Venezuela's production fell at a faster rate than its exports.
EIA forecasts that Venezuela's crude oil production will continue to fall through at least the end of 2020, reflecting further declines in crude oil production capacity. Although EIA does not publish forecasts for individual OPEC countries, it does publish total OPEC crude oil and other liquids production. Further disruptions to Venezuela's production beyond what EIA currently assumes would change this forecast.
Headline crude prices for the week beginning 13 May 2019 – Brent: US$70/b; WTI: US$61/b
Headlines of the week
Midstream & Downstream
The world’s largest oil & gas companies have generally reported a mixed set of results in Q1 2019. Industry turmoil over new US sanctions on Venezuela, production woes in Canada and the ebb-and-flow between OPEC+’s supply deal and rising American production have created a shaky environment at the start of the year, with more ongoing as the oil world grapples with the removal of waivers on Iranian crude and Iran’s retaliation.
The results were particularly disappointing for ExxonMobil and Chevron, the two US supermajors. Both firms cited weak downstream performance as a drag on their financial performance, with ExxonMobil posting its first loss in its refining business since 2009. Chevron, too, reported a 65% drop in the refining and chemicals profit. Weak refining margins, particularly on gasoline, were blamed for the underperformance, exacerbating a set of weaker upstream numbers impaired by lower crude pricing even though production climbed. ExxonMobil was hit particularly hard, as its net profit fell below Chevron’s for the first time in nine years. Both supermajors did highlight growing output in the American Permian Basin as a future highlight, with ExxonMobil saying it was on track to produce 1 million barrels per day in the Permian by 2024. The Permian is also the focus of Chevron, which agreed to a US$33 billion takeover of Anadarko Petroleum (and its Permian Basin assets), only for the deal to be derailed by a rival bid from Occidental Petroleum with the backing of billionaire investor guru Warren Buffet. Chevron has now decided to opt out of the deal – a development that would put paid to Chevron’s ambitions to match or exceed ExxonMobil in shale.
Performance was better across the pond. Much better, in fact, for Royal Dutch Shell, which provided a positive end to a variable earnings season. Net profit for the Anglo-Dutch firm may have been down 2% y-o-y to US$5.3 billion, but that was still well ahead of even the highest analyst estimates of US$4.52 billion. Weaker refining margins and lower crude prices were cited as a slight drag on performance, but Shell’s acquisition of BG Group is paying dividends as strong natural gas performance contributed to the strong profits. Unlike ExxonMobil and Chevron, Shell has only dipped its toes in the Permian, preferring to maintain a strong global portfolio mixed between oil, gas and shale assets.
For the other European supermajors, BP and Total largely matched earning estimates. BP’s net profits of US$2.36 billion hit the target of analyst estimates. The addition of BHP Group’s US shale oil assets contributed to increased performance, while BP’s downstream performance was surprisingly resilient as its in-house supply and trading arm showed a strong performance – a business division that ExxonMobil lacks. France’s Total also hit the mark of expectations, with US$2.8 billion in net profit as lower crude prices offset the group’s record oil and gas output. Total’s upstream performance has been particularly notable – with start-ups in Angola, Brazil, the UK and Norway – with growth expected at 9% for the year.
All in all, the volatile environment over the first quarter of 2019 has seen some shift among the supermajors. Shell has eclipsed ExxonMobil once again – in both revenue and earnings – while Chevron’s failed bid for Anadarko won’t vault it up the rankings. Almost ten years after the Deepwater Horizon oil spill, BP is now reclaiming its place after being overtaken by Total over the past few years. With Q219 looking to be quite volatile as well, brace yourselves for an interesting earnings season.
Supermajor Financials: Q1 2019