Y. Kargina. Rollercoaster Ride: Overview of the North American Oil Markets

BP's Na Kika platform in the Gulf of Mexico at sunrise on June 12, 2013.

Yelena Kargina – senior TASS Correspondent

The North American energy industry is usually associated in Russia with the United States oil-and-gas market and their «shale revolution» which, on the one hand, allowed the USA to take first place in oil production in 2018, and on the other, brought serious risks of a disruption in the global energy balance. Meanwhile, such major oil-producing countries as Canada and Mexico, which are undeservedly paid much less attention, are firmly involved in the continent’s energy system. Canada occupies an honorable fourth place in the global ranking of oil production and exports. Mexico’s energy industry is currently experiencing a difficult time: the country, which ranked sixth in terms of oil production in 2004, dropped to twelfth last year. However, despite such a catastrophic fall, Mexico continues to have a serious influence on the global oil market.

Canada: Reduction in Quantities and Infrastructural Limitations Status of the Sector

As of the end of 2018, Canada ranked third in the world in terms of recoverable oil reserves (10% of world reserves, or 166.7 bln barrels), but the country was producing only 5% of global production (4.6 Mmbd). Almost all of the country’s oil reserves (96%, or 162.5 bln barrels) are concentrated in the oil-bearing sands, whereas at present, about 64% of all Canadian oil is extracted from bitumen – about 2.91 Mmbd.
The country’s main oil-producing region is Alberta, which accounts for more than 80% of total national output. As of today, the volume of capital investments in the oil-bearing sands is estimated at 313 bln Canadian dollars, including that of last year – at CAD10.4 bln. More than half of all Canadian oil is produced by the five largest companies: Suncor, Canadian Natural Resources Limited, Imperial Oil, Husky and Cenovus.
Canada exports more than 80% of its oil. The main market is the United States, which isn’t surprising. Last year, Canada provided nearly half of its neighbor’s oil imports, or 3.5 Mmbd. At the same time, due to the technological features of its local oil refineries, Canada also has to purchase small volumes of crude from the USA, Saudi Arabia, Norway and even Azerbaijan.
One of the main problems that the Canadian oil industry has been facing in recent years is serious infrastructural restrictions on oil transportation, which are inexorably leading to a reduction in production, lower capital expenditures in the sector, and the withdrawal of several world companies from the market. Oil production from bitumen sands has doubled over the decade prior to 2018, and throughput capacities simply cannot keep up this pace, especially given the ambiguous policy of the country’s liberal government in this area, which focuses primarily on the environmental component of projects. In addition, in the opinion of experts, the government is not making enough of an effort to create the conditions necessary for the diversification of hydrocarbon exports and development of pipeline capacities.
It should be noted that the Canadian oil-and-gas industry is still recovering after the 2014 crisis, when a number of important energy projects were suspended due to the drop in hydrocarbon prices.

Table 1. Key projects for the construction of new oil pipelines in Canada
Source: Canada Energy Regulator

Restrictions in the Name of Environmental Protection

Over the summer, the Canadian Association of Petroleum Producers (CAPP) reduced its forecast for growth rates in the country’s oil production through 2035. Experts now expect that production here in 2019–2035 will increase by 1.4% annually, whereas as early as 5 years ago, they were predicting production growth of roughly 2.5%. Today, it is assumed that by 2035, Canada will produce 5.86 Mmbd, which is 1.27 mln higher than the current level. At the same time, the Association predicts a 1.5-fold increase in bitumen oil production, up to 4.25 Mmbd, compared to 2.9 Mmbd in 2018.
The organization explained the forecast adjustment by pointing to the aforementioned lack of pipeline capacity, the virtual absence of market diversification, and inefficient governmental regulation of the sector, which does not allow for attracting enough private investments. Over the last six years, capital expenditures for development of the country’s oil-and-gas projects have been more than halved – to CAD37 bln (roughly USD28 bln) in 2019 from CAD81 bln (USD61.5 bln) in 2014.
The country’s oil companies have accumulated many grievances against the Canadian Prime Minister Justin Trudeau, who has declared combatting climate change one of the main goals of his liberal government. Thus, the Senate of Canada had recently approved the so-called bills S‑69 and S‑48, which impede the construction of new pipelines and extend the moratorium on the use of oil tankers with a displacement of more than 12.5 K tons along the northern coast of British Columbia or smaller vessels for subsequent loading to such tankers. This decision was made to prevent potential oil spills, but it has already caused a storm of protest in the industry.

Oil sands in Alberta

Canada currently has a limit on oil production in the amount of 325 K barrels per day (almost 9% of total production). In October 2019, this limit should be reduced to 100 kbpd. It is still unknown whether these plans will be implemented, but the government of J. Trudeau has already extended the period of mandatory restrictions on oil production through the end of 2020, although it was initially assumed that they would be lifted in December 2019. The government explained its actions by pointing to the lack of transport capacities.
Despite all of the debates surrounding this action, the restrictions helped to raise the price of the Canadian oil Western Canada Select. It is currently traded at a discount of 10–15 dollars per barrel against West Texas Intermediate, although prior to the introduction of the restrictions in the fall of 2018, the discount exceeded 40 dollars per barrel.
Oil supplies to the United States by rail presume a discount of about 15–17 dollars per barrel against WTI, whereas Goldman analysts forecast this indicator at an average of 17.5 dollars per barrel in the third quarter, 20 dollars in the fourth quarter and 21 dollars on average in 2020.
Moving forward, experts are certain that the discount could continue to grow. In their opinion, the International Maritime Organization’s (IMO’s) standards governing sulfur content in marine fuel, which are slated to come into force in 2020, will negatively affect Canadian heavy oil. The high-sulfur fuel market will slump, which will lead to cheaper crude materials for its production.

Enough Oil But Not Enough Pipelines

Despite the limits on oil production, development of the industry in Canada continues to be hindered by the lack of export pipelines, which threatens to delay a number of major investment projects in the industry. Among the most vulnerable, Goldman Sachs experts have named Imperial’s Aspen project, Canadian Natural’s Horizon expansion projects, and Suncor at Fort Hills.
The fate of the Trans Mountain Pipeline capacity-­expansion project from the current 300 to 890 thousand barrels per day for pumping oil from Alberta to the west coast of British Columbia is still unclear. Initially, the 1,150km-long oil pipeline was supposed to become operational at the end of this year, but the project has faced many obstacles. Last year, the «pipe» was essentially nationalized by the Canadian government, which bought it from Kinder Morgan for USD3.4 bln to guarantee its implementation. However, only a month later, the country’s court blocked the construction due to the need for additional consultations with the indigenous population.
Now, pipeline construction work has resumed after obtainment of the required permits. According to the most optimistic scenario, triple the oil volume will pass through it in mid‑2022. However, litigation between oil producers, environmentalists and the indigenous population is far from over.

Оil pipeline in Canada

Another project with a «difficult fate» is the Keystone pipeline, with a total length of 1.9 thousand kilometers and a throughput capacity of more than 800 kbpd, which envisions the transportation of oil from Canadian Alberta to the refineries on the coast of the Gulf of Mexico in the United States. The project, which has been delayed for a decade already, was rejected by one US president, then approved by another, and came up against the fierce resistance of environmentalists and indigenous groups, resulting in harsh judicial squabbling. TransCanada changed the pipeline’s route many times, but to no avail. Currently, the company remains embroiled in complex and labyrinthine litigation with the project’s opponents.
The third line of the Enbridge pipeline, which was built in the 1960s, is also under reconstruction.
As far back as six years ago, TransCanada proposed building another pipeline, this time to the country’s east coast under the name Energy East with a capacity of 1.1 Mmbd. In 2017, the company abandoned the project against a backdrop of unfavorable market conditions, but the possibility of returning to it has not been ruled out in case of a change in the Canadian government. At any rate, Alberta’s oil authorities continue to lobby for this pipeline.
Gloomy colors are being added to the emerging picture of the world by the withdrawal of business from the country’s oil industry, estimated by experts at $30 bln over the last three years. The US company Kinder Morgan is selling its assets, ConocoPhillips has already assigned its projects for $13.2 bln to Cenovus Energy, and Shell and Marathon have quit the oil-sands development business in favor of Canadian Natural Resources for $10.7 bln.
All of the industry’s hopes are now pinned on the parliamentary elections to be held in Canada in October. Petroleum companies are anticipating a change in the political course in the energy sector, which will give hope for the oil-and-gas industry’s emergence from the five-year-old crisis.

USA: Has the Growth Limit Been Reached or Is the Best Yet to Come?

Against the backdrop of the negative mood of its northern neighbor, the US oil industry is feeling confident like never before. The «shale revolution» that began ten years ago, which was not taken seriously by the world for far too long, has turned the energy market upside down – not only in the United States, but across the entire planet.
The USA is now the world’s largest oil-and-gas producer, relegating Russia to second place. The country’s oil production exceeds Russia’s by almost 20%, and gas production – by 25%. According to the Joint Organizations Data Initiative (JODI), in June, US oil production was 12.61 Mmbd, and Russia’s – 10.58 Mmbd. At the same time, oil exports from the USA grew by 18% in June, to 3.41 Mmbd.
The price collapse observed in 2014–2017 caused many American shale-­production companies to cut costs in order to survive. The number of small companies filing bankruptcy claims is still growing. In just the first half of 2019, the number of small shale-oil producers declaring bankruptcy has risen to the level of all of 2018.

Table 2. Forecast for oil production in September 2019 of the seven major US shale formations

Record After Record: What’s the Catch?

Large oil giants have long approached the Permian Basin with caution, but they finally seem to be enjoying it. And against the backdrop of the exit of smaller players, they’re beginning to report their successes with increasing vibrancy. America’s ExxonMobil, for example, announced plans to reduce the cost of oil production in the Permian shale formation to $15 per barrel – a corporation has only managed to achieve such a level of costs in the Middle East fields. The head of Exxon XTO Energy, Stole Jervik, predicts that production in the Permian Basin could double by 2025, while Exxon itself will bring production in the region to 1 mln barrels of oil equivalent. Another major player – Chevron – has already promised to double in four years its production rate to 900 thousand barrels of oil equivalent per day.
In December 2015, the US Congress lifted a 40-year ban on American oil exports. After that, Exxon was the first among local companies to send oil abroad. In the fall of 2018, the country briefly became a net exporter of oil and petroleum products – for the first time in 70 years.
US Department of Energy experts predict that the country will become a full-fledged net exporter of oil by 2020. Specialists from the International Energy Agency (IEA) say that this will happen a year later. However, both of them agree on one thing: the process has already become irreversible. Moreover, the IEA is sure that in the next five years, the United States will overtake Russia in terms of oil exports.

Shale oil production in US

For the first time, the United States broke its own almost half-century-old record in the production of liquid hydrocarbons in November 2017, ramping up production to more than 10.1 Mmbd. Since then, production has been growing steadily: according to the latest EIA forecast, production in 2019 will be 12.27 Mmbd, in 2020–13.26 Mmbd. However, it should be noted that this forecast has already been adjusted downward by 90 thousand barrels.
According to IEA estimates, in September, the production of so-called shale oil reached a record of 8.77 Mmbd, while the Permian Basin posted the highest growth, where the maximum production in history is expected to reach a peak of 4.42 Mmbd.
Experts around the world are wondering where the limit of this growth is – and whether it has already been reached in 2019. Rystad Energy analysts haven’t yet changed their June forecast of an increase in US oil production to 13.4 Mmbd in December 2019. In their opinion, only the Texas fields will produce 5 Mmbd, which is more than any OPEC member produces other than Saudi Arabia.
The IEA announced a decrease in June oil production to 12.08 mln barrels from 12.1 mln in May. The decrease is insignificant; in July, however, experts weren’t expecting growth due to seasonal hurricanes and the stoppage of work in the Gulf of Mexico. In August, production stood at an average of 12.36 mln barrels. Should we expect a significant increase in production in the remaining months of this year? If anything, what’s at issue is reaching a kind of record «shelf»– the only question is for how long.
Yet, according to a number of forecasts, made before the destruction of infrastructure capacities in Saudi Arabia, over the short- and mid-term, the price of oil will not exceed $55 per barrel, amid the US-China trade conflict and a macroeconomic slowdown in American economic growth rates. Such pessimistic forecasts are leading to lower drilling volumes and financial difficulties, especially for small companies.
Against the backdrop of the expectation of low hydrocarbon prices, producers are cutting budgets, personnel and reducing their production forecasts. The data available so far indicate a slight slowdown in production, and the investment bank Cowen & Co said that oil companies are expected to reduce total costs this year by 11%.
The oilfield service company Halliburton reported an 8% personnel reduction in North America and warned of a slowdown in regional activity, while Schlumberger reported a 12% decline in regional profit in the second quarter.
However, the larger companies don’t look too worried about the industry’s decline, publicly declaring that they remain capable of controlling revenues under conditions of low prices. Exxon, for example, assures that for it, the Permian Basin is profitable at a price of $35 per barrel.
Against this backdrop, the trend towards consolidation and the takeover of small companies by more successful large players is becoming more and more noticeable. This spring, the global market watched with bated breath a war of offers between Occidental Petroleum and Chevron for acquisition of Anadarko. Occidental emerged victorious, announcing that it was ready to pay $55 bln for the asset. Undoubtedly, this is only the first sign, and large players aren’t even hiding that they have taken a wait-and-see approach and are closely watching the smaller independent producers.
The «search for opportunities» in the Permian Basin was announced, in particular, by Exxon, Shell, Chevron. The investment bank Tudor, Pickering, Holt & Co has already «distributed» the tasty morsels – Pioneer Natural Resources or Concho Resources, for example, would be just fine for Exxon, while Shell could be content with smaller players like WPX Energy or Cimarex Energy. Even the larger companies, such as EOG Resources or even Occidental Petroleum, could become a takeover target.
It is now being remarked with increasing frequency that in the coming years, the productivity of wells should emerge as the key factor in American productivity growth (or decline). From 2010 to 2018, the average productivity of horizontal wells increased by 30%. But, for example, Dan Stiffens, President of Energy Prospectus Group, insists that the US shale industry has come to the end of its path of productivity growth. Raymond James analysts explain that although, over the past eight years, IP‑30 (initial productivity in the first 30 days of production at well) has grown at 30% annually, the main growth was at the beginning of decade, and in 2017, this indicator increased by 11%, in 2018 – by 15%. In the first seven months of this year, according to analysts, it has grown by just 2%. Perhaps the problem is that the growth limit has already been reached?
If we look at the first three months of production, the situation seems to be even worse: according to that indicator, for the first half of the year, there has been an average production slide of 2% across the country, and a 10% drop in the Permian Basin in particular.
The decline is explained by the fact that in the first years, companies focused all of their efforts on the best reserves, and now the resource base of these areas is constantly deteriorating. In addition, the distance between wells is being reduced, and companies are returning to drilling «children» wells after depletion of the parent wells.
Rystad Energy analysts believe that the pessimism about the decline in productivity is premature and note that the average productivity of new wells in the Permian Basin remains at historically-­maximum levels. According to their data, an average well in the second month of production, traditionally peak, produces about 830 barrels per day.
The fact is confirmed that the world’s oil companies are pulling ahead and for the first time in several years may have outstripped the top 10 US shale-oil developers in terms of horizontal well productivity.


The boom in shale-oil production confronted the United States with the problem of infrastructure capabilities for its transportation, including exportation. In fact, the USA has been an importer of «black gold» for too long, rather than its seller. According to the IEA, over the last week of August, the country exported 3.06 mln barrels per day (with imports amounting to 6.9 mln barrels). Faced with a bottleneck, US companies proposed several projects for the construction of pipelines and specialized marine terminals on the coast of the Gulf of Mexico.
In August, the Cactus II Plains All American Pipeline was launched from the Permian Basin to Corpus Christi in Texas, with a capacity of 670 kbpd. Also in August, EPIC Midstream Holdings started the supply of oil through its 600-kbpd pipeline to the Gulf of Mexico coast.
By the end of the year, the launch of the Gray Oak project, with a throughput capacity of 900 kbpd and Permian Express with a capacity of 120 kbpd is expected. Thus, when the projects reach their full capacity within six to eight months, it will be possible to deliver 4 Mmbd by those pipelines to the Gulf of Mexico coast.
Of course, the development of seaport infrastructure is also necessary for exports. There are about a dozen proposals for the construction of specialized new sea ports in the area of the Gulf of Mexico, in addition to plans for the reconstruction of existing terminals. According to various estimates, export flows from the ports of the Gulf of Mexico could reach from 6 to 8 Mmbd in the near future. And that’s not the limit. How much of this oil is needed on a market accustomed to a constant flow of supply is another matter. The only thing that’s clear is that this will become another headache for OPEC+ countries.

Mexico: Has It Hit Bottom?

If, regarding the United States, the question is whether the country has reached the maximum level of oil production, then the situation with Mexico is exactly the opposite: experts argue whether the country has reached its bottom of production and when, finally, growth is to be expected.
The energy industry in Mexico is going through difficult times: over the past six years, the production of the state-­owned Pemex Corporation has dropped by 30%. In 2018, it decreased by 7% to 1.813 Mmbd. If we compare this result with that of 2004, when the country was at the peak of production, it means that oil production decreased by half. Pemex debt is now the largest in the industry, exceeding $104 bln, excluding pension obligations.

fig. 1. Pemex financial debt growth over twenty years
Source: Pemex

The country’s proved category 1P hydrocarbon reserves over the past year decreased by 7% and amounted to 7.9 bln barrels of oil equivalent, including oil reserves, which decreased by 6% to 6.06 bln barrels. The decrease in the volume of prospecting operations has led to a decrease in the country’s proved and probable hydrocarbon reserves (2P) by 2%, to 15.84 bln barrels of oil equivalent, and proven, probable and possible (3P) by 1.4%, to 25.1 bln barrels of oil equivalent.
The situation is being exacerbated by the country’s energy policy in the wake of the electoral victory of left-leaning presidential candidate Andrés Manuel López Obrador last year. Since 2013, the country has been implementing energy reforms which, for the first time in eighty years, has admitted private and foreign capital into hydrocarbon-­production projects. Thanks to these energy reforms, private companies such as ENI, China Offshore, Total, Exxon, Chevron, Ecopetrol, Repsol, Shell, Qatar Petroleum, BP, Pan American, as well as Russian LUKOIL and Mikhail Fridman’s DEA Deutsche Erdoel have come to Mexico.
But the new president of Mexico, with his ambiguous rhetoric, called the reforms a failure and demanded that their organizers and advocates apologize to the people of the country. With or without apologies, the new authorities have stopped holding tenders for land plots for private companies, including foreign companies, as well as farm-outs. They explained the step by pointing to the need to check how existing contracts are being performed, and how much they are in the interests of the country.
Andres Obrador proclaimed that his key objectives in the oil-and-gas industry include combatting corruption in all areas, restoring production, eliminating illegal fuel thefts (which, he said, have assumed a simply monstrous scale) and focusing on the domestic processing of hydrocarbons. Currently, Mexico, an oil producer, is forced to import more than 60% of the gasoline consumed in the country due to its lack of processing capacity.
All of the tasks are extremely complicated, and it’s still difficult to say the extent to which Obrador can handle them. Indeed, as a source of income for the fight against corruption, he’s suggested using the money of the corrupt officials themselves.
According to his plan, Pemex will maintain oil production in 2019 at the level of 1.8 Mmbd, and in 2020 it will be increased by 11% to 2 Mmbd. In the summer, the country’s authorities said that for the first time in 14 years, the trend of decline had been overcome: in June and July, production held steady at 1.67 Mmbd. These figures remain more than minimum – compared with July 2018, it’s clear that production has dropped by 8%. So, it’s too early to talk about overcoming the crisis and the start of the industry’s prosperity.
The economic plan of the country’s president presumes an unprecedented increase in daily oil production in 2020 to 1.951 mln barrels. This is 17% higher than in the summer of 2019. Mexico has not been able to achieve such an ambitious surge in production for nearly forty years, when the giant Cantarell project was commissioned. Exports in 2020 are planned at 1.13 mln barrels; Mexican oil prices are projected at $49 a barrel, compared with the previously-­estimated 55 dollars.
The presidential administration calls these plans quite realistic, but it should be noted that so far, the state of the country’s economy suggests that they should be regarded rather skeptically.
By the end of his six-year presidential term (2024), A. Obrador is promising to increase production to 2.4 mln barrels.

Thunder Horse at SuSea platform in Gulf of Mexiconset

But Where Will the Money Come From?

Mexico has announced unprecedented financial and fiscal measures to support Pemex starting from 2019. In mid September, the government promised to inject an additional $5 bln into the company, due to which Pemex will be able to make payments on securities maturing in 2020 and 2023, as well as to issue new seven-, ten- and thirty-year bonds. In total, the authorities will support the oil company with $9.5 bln in 2019. In addition, Pemex has been relieved of its fiscal burden – in 2019, at issue is about $1.56 bln in various breaks and concessions, including a change in the tax treatment of a number of the company’s wells. For the years 2020–2021, tax exemptions of approximately $6.7 bln are expected.
However, from the market standpoint, even such measures seem to be unconvincing: Fitch Ratings called them «moderate,» saying that this is only short-term assistance compared to the tremendous financial burden on the company. In turn, Moody’s stated that the chance of it increasing the company’s credit rating in view of such support is unlikely, and quite the contrary, didn’t rule out a downgrade.
In such severe financial straits, it would seem logical to attract foreign partners to oil-production projects. But the Mexican administration hasn’t yet found an acceptable compromise. On the one hand, the CEO of Pemex, Romero Oropesa, has already announced the possibility of attracting foreign investments to implement part of the company’s projects on the principles of «openness to business arrangements with the private sector, strictly following its interests, with fair and transparent agreements.» On the other, Deputy Minister of Energy Alberto Montoya is maintaining that the decision to involve private companies in development of the deep-water fields offshore in the Gulf of Mexico, as well as in gas-production projects, has not yet been made.
The company itself, as its financial director stated, will not invest in the exploration and development of unconventional reserves or in «deep water» until at least 2024, focusing instead on land and shallow deposits. During the energy reforms, Pemex engaged BHP Billiton, an Australian service company, for the Trión deep-water project in the Gulf of Mexico, but its first production is expected no earlier than 2025. The focus on onshore areas and projects in shallow water has a simple explanation: the lack of the necessary financial resources and infrastructure, of sufficient experience in deep water and unconventional reserves, the lack of proprietary technologies and an unwillingness to cooperate with foreign partners. Obviously, this strategy is a glaring failure under current conditions.
Nor does Mexico intend to follow the example of its northern neighbor, i. e. pursue fracking. At any rate, Obrador has repeatedly publicly rejected use of the hydraulic fracturing method. Two years ago, under the previous government, Pemex engaged the American Lewis Energy for the evaluation and exploration of the Olmos shale-­hydrocarbon field in northern Mexico, which is part of Eagle Ford. The use of fracking was not announced then directly, but the application of this particular method seemed to be quite logical.
At the same time, Mexico has charted a course for an increase in oil-refining capacity. The country announced plans to reconstruct existing refineries and build a new, seventh-in-a-row, refinery in Tabasco. Experts noted that the project does not look very profitable, given its location in the area of mangroves at an altitude close to sea level. Initially, the country offered participation in construction to a consortium of the American Becthel and Italian Techint, American Jacobs with Australian Worley Parsons, American KBR and French Technip (which later withdrew its proposal). The cost of the plant, according to the authorities» project design, should not exceed $8 bln. Its construction was to be completed in the spring of 2022. However, it later emerged that the companies weren’t ready to build the plant within such a short timeframe. And the amount of investments seemed to be insufficient. As a result, Mexico announced that it will implement the project on its own. How realistic this is only time will tell, but many of the country’s experts in private conversations with the author of this article were extremely skeptical about the prospects.
The Mexican government, with its inherent populism, is reporting about the industry’s achievements. According to Energy Minister Rocio Nale, this year, the country’s oil refineries will achieve refining of 1 Mmbd, which is 200 kbpd higher than the indicators at the beginning of the year. In 2020, the country intends to increase its processing capacity to 1.46 Mmbd – this forecast, according to many experts, is also overly optimistic.
So, the Mexican administration must still find an answer to the question: whether to assign part of the national reserves to foreign capital in order to increase the industry’s liquidity, or try to find and use its own resources and technologies for the development of deep-sea projects without the proper approbation and try to introduce them with a threat to their own energy security, but with preservation of the resource base in national ownership. The latter scenario seems to be slightly utopian.

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