A Saudi Predator?

How market manipulation helped the kingdom become a major investor in western oil companies

By Peter McKenzie-Brown

The last twelve months have been rough for companies invested in Alberta’s oil sands. Things began rough, with Norway’s US$1 trillion sovereign wealth fund, which has its origins in the country’s offshore oilfields, announced that it would unload the US$81 billion it had invested in bitumen companies. The reason? Such an investment was out of alignment with the 2^oC global warming target set by the 2016 Paris Agreement on greenhouse-gas-emissions. “By going…oil sands free,” the Norwegian news release said, “we are sending a strong message on the urgency of shifting from fossil to renewable energy.”

A strong message it may be, but also haughty. There is a direct correlation between a nation’s oil consumption, its GDP and the quality of life its citizens enjoy. By what right could the world’s rich nations – for practical purposes, the 37 members of the Organization for Cooperation and Development, with a population of about 1.3 billion – justify denying affordable energy to other countries in the world? Well, there is the matter of the global warming emergency.  The case for developing alternative energy resources is dire. After all, the population of our planet is rapidly approaching eight billion.

Norway’s wealth fund soon sold its US$81 billion interests in Calgary-based Cenovus Energy Inc., Suncor Energy Inc., Imperial Oil Ltd. and Husky Energy Inc. From that point on, the statement said, the fund would exclude companies involved in the oil sands from consideration as appropriate investments.

The shares in those companies responded immediately by falling. Even though there is widespread concern about global warming in Alberta, many of us with backgrounds in the oil patch felt affronted. “What else could go wrong?” we wondered. We did not know it at the time, of course, but there would soon be the matter of COVID-19.

As the dangers of travel across a pandemic-stricken planet became obvious, governments imposed lockdowns around the world and global oil consumption plummeted. As international travel crumbled, oil prices dropped for an industry which cannot too quickly shut in production. The poster-child for this event came on April 20^th, when the headline price for a barrel of West Texas Intermediate oil fell into negative territory for the first time ever. For the only time in history, sellers had to pay buyers to take their oil. (See chart.)

                Why did it happen? Essentially, because of the way oil markets function in Texas. The Texas Railroad Commission is the steward of the oil-rich state’s natural resources and the environment, and its regulations led to the reality of oil prices crashing from US$18 a barrel to -US$38 in a matter of hours. Rising stockpiles of crude threatened to overwhelm storage facilities and forced producers to pay buyers to take the barrels they could not store. Was this the doing of big oil – such vast publicly-traded oil companies as ExxonMobil, British Petroleum and Royal Dutch Shell, which are so often characterized as villains when pump prices rise at your local gas station.

In fact, the world’s 13 largest energy companies, measured by the reserves they control, are government-owned and operated – by name, Saudi Aramco, Gazprom (Russia), China National Petroleum Corp., National Iranian Oil Co., Petróleos de Venezuela, Petrobras (Brazil) and Petronas (Malaysia). These state-owned companies and their smaller siblings control more than 75 percent of global production. By contrast, the multinationals produce only ten percent.

Markets, manipulated

In early March, OPEC officials presented an ultimatum to Russia to cut production by 1.5 percent of world supply. For her part, the Eurasian giant foresaw continuing cuts in her market share: after all, America’s shale oil production, which uses fairly new technology, was making the country both the world’s largest consumer of oil and the largest producer. Anxious about this concern, Putin’s government rejected the demand – in effect ending a three-year partnership between OPEC and major non-OPEC producers, widely known as the OPEC Plus cartel. Another factor was weakening global demand resulting from the COVID-19 pandemic. This also resulted in OPEC Plus failing to extend the agreement cutting 2.1 million barrels per day that was set to expire at the end of March. Saudi Arabia, which has absorbed a disproportionate amount of the cuts to convince Russia to stay in the agreement, notified its buyers on March 7^th that they would raise output and discount their oil in April. This prompted a Brent crude price crash of more than 30 percent before a slight recovery and widespread turmoil in financial markets.

Perhaps this Saudi-Russian price war was a game of chicken to see who would blink first. But neither of the major players had much reason to blink. In March 2000, the Saudis had US$500 billion in foreign exchange reserves; Russia had US$580 billion. More to the point, the Saudi cost of production, depending on the grade produced, is three dollars per barrel, compared to US$$30 per barrel in Russia.

Thus, the OPEC plus price war was designed to take advantage of a weak global economy, infected by COVID-19. It Saudi Arabia's case, it assaulted the Western petroleum sector – especially America’s. To ward off from the oil exporters price war which can make shale oil production uneconomical, US may protect its crude oil market share by passing the NOPEC bill.

In April 2020, OPEC and a group of other oil producers, including Russia, agreed to extend production cuts until the end of July. The cartel and its allies agreed to cut oil production in May and June by 9.7 million barrels a day, equal to around 10 percent of global output, to prop up prices, which had previously fallen to record lows.

The Russia/Saudi Arabia oil price war, which had begun the previous month, had a huge impact – probably by design – on the ownership of large oil companies in Europe and North America. Saudi Arabia’s sovereign wealth fund saw nothing but opportunity in the global oil price plunge. During the battle, the kingdom scooped up billions of dollars’ worth of shares in downtrodden energy companies, including Canadian firms.

Filings with U.S. Securities and Exchange Commission indicate the kingdom’s Public Investment Fund (PIF), which has an estimated US$320 billion in assets under management, bought stakes worth US$481 million and US$408 million in Suncor and Canadian Natural Resources, respectively, during the first quarter of 2020. That month, the values of the Canadian producers and three other energy stocks PIF bought — Royal Dutch Shell plc, Total SA and BP plc — had all more than halved from their 52-week highs at the time the kingdom made its acquisitions. The illustration shows the prototypical Royal Dutch share price after the crash. It also shows the quick return the kingdom made from the package of acquisition of these five stocks as markets rebounded: more than US$182.6 million since the end of March.

Cures for Distressed Barrels

North American refiners and pipeliners are working hard at near- and long-term solutions for the differential-mushrooming Midwest supply glut. 

An edited version of this article appears in the Oilsands Review 

By Peter McKenzie-Brown
After the financial crisis of 2008, the United States was flat on its back. Since that terrible period, Canada’s energy industry has been a considerable, though unwilling, contributor to its return to financial health. To a large degree because of the glut of bitumen in much of its heartland, the US is enjoying lower energy prices than other oil-importing countries. Because of the perverse economics of oilsands development, from many perspectives – not least that there are no alternative markets – it makes short-term sense to keep sending cheap bitumen into the growing glut.

Behind this debacle is a continental pipeline system that does not reflect the realities of contemporary oil supply. In a Globe and Mail report, Canadian Association of Petroleum Producers (CAPP) chairman Lowell Jackson described the industry as “taking the short end of the stick…simply because we can’t move product.” The solution? More pipelines to more markets.

A Manageable Glut
There are four reasons for the glut in much of the American oil market. First, the country is consuming less – a response to higher oil prices, lower economic activity and government policy. Second, the US is producing more oil for the first time in years – much of it coming from the Bakken play in North Dakota and Montana. Those growing supplies are a response to new production technologies – essentially the use of horizontal wells and hydraulic fracking to release tight oil from shale. Third, Western Canada exports its oil almost exclusively on the American Midwest. Finally, both bitumen and light oil production are growing rapidly in Western Canada despite the region’s limited markets.

After being in decline for decades, light oil production in Alberta is again at 2003 levels. In three years nearly 100,000 barrel-per-day of new production have taken the total to 400,000 barrel-per-day. Adding to the supply is Canadian synthetic oil and bitumen production, which increased by more than 100,000 barrels a day last year alone, to around 1.8 million barrels.

Those new volumes are fighting for market share in already tight segments of the American market, which is divided into five PADDs (Petroleum Administration for Defense Districts). Of the five districts, three – respectively encompassing the US East Coast, the Gulf Coast and the West Coast – are the largest oil consumers. However, according to Ralph Glass, economist and vice president of consultancy AJM Deloitte, “80 to 90% of the oil exports coming down from Canada are going into PADD 2 (the Midwestern states) or PADD 4 (the Rocky Mountain states). The other three PADDs are where the population is. So the problem is that you can’t get the oil from these relatively unpopulated places to the densely populated states that really need it – California and Florida, for example.”

He added that the other three PADDs are mostly fed by offshore oil, so they have to deal with offshore prices. “They are paying $15-$20 more per barrel for oil coming in from the offshore, even if it’s coming in from a Gulf of Mexico platform.”

Since Canadian export markets rely on a system of pipelines that feeds Midwestern markets from producing fields in Western Canada and the Western states, the competition for access to limited pipeline capacity is huge, and it is leading to huge differentials for Canadian oil. To cite one example, synthetic crude was recently selling for $10 per barrel less than West Texas Intermediate (WTI), although it is clearly higher-quality oil.

Pipeline capacity is relatively tight already. According to CAPP vice president Greg Stringham, “really small incidents that wouldn’t have had much impact in the past are now having a big impact on crude throughput.

The real disconnect is between WTI prices and world prices. In the next year a lot of market pressure is leading to a lot of infrastructure development with the idea of eliminating the differences between. A lot of that will be resolved within the next year and a half or so.”

Part of the solution will actually make things worse for the oilsands sector. At present, there is no major pipeline coming out of the Bakken; that oil is still mostly railed to market. The magnitude of the potential issue became clear when an American company recently proposed the 2,100-kilometre Bakken Crude Express Pipeline, a 200,000 barrel-per-day pipeline to deliver crude from North Dakota’s Bakken play to Cushing Oklahoma. When completed in 2015, the line will carry high-quality sweet oil into an already competitive market. That line could further reduce Canadian access to US markets by increasing the glut.

Winners and Losers
Alberta – which receives royalties in kind – receives lower royalty revenues because of the differentials. The differentials also affect the corporate bottom line, bringing down governmental tax revenues. In eastern Canada, refineries pay the much higher Brent prices. “The widening differential between Brent and WTI is an indication of the over-supplied North American market and limited access to the off-shore markets,” Glass added.

According to Glass, if the price differentials of early spring this year were to hold until year end, the Canadian economy would forego about $18 billion in revenue, royalties and corporate taxes. What happens on the other side of this trade? North American refiners that can process bitumen – almost entirely located in the US – make high returns by buying bitumen feedstock when differentials are high and selling refined products at regular market prices. The beneficiaries of the oil glut are mostly American.

Perverse oilsands economics mean it makes sense to sell bitumen even when there is no profit in it. Some companies have suggested that, if you apply full-cost accounting to bitumen production, they are selling product to refiners at cost. Yet it makes sense to continue doing this once the capital investments have been made because the cost of is low – perhaps $20-$30 per barrel for SAGD production. According to one bitumen trader, “operating costs are partly subsidized by the gas price collapse. Even if we only get $60 a barrel (from the buyer), we want the income stream.”

Some companies, though, use hedging strategies to beat the differentials. Beginning in 2006, three Canadian companies – Cenovus, Husky and Suncor (through the Petro-Canada takeover) – have taken deliberate steps to average away these peaks and valleys by acquiring interests in bitumen-processing US refineries. They benefit from high bitumen prices when differentials are low (and bitumen prices therefore high.) Conversely, their refining operations benefit when differentials are high, since products manufactured from lower-cost feedstock yield better returns.

Relative to the rest of the world, the energy industry is subsidizing the American economy. “The Americans see the advantage of taking as much Canadian oil as they can because it is significantly cheaper,” according to Glass. “The push by American refineries to get their hands on Canadian oil (will increase summer demand). I think that over the summer the synthetic price will pick up again, too, as it did last year. The Americans are building up their storage reserve with cheaper oil from Canada.”

But “I see the immediate issue as a short-term problem,” he added. Large price differentials “happened last year about this time, but rectified themselves by the end of summer. There is some capacity to put new oil into the pipeline system to get it to the US. Last year Edmonton par actually received a premium over WTI.”

“Enbridge is reversing the Seaway pipeline and that should help. Also, President Obama has announced that he wants to push ahead with the southern leg of Keystone XL…” Access to the Gulf Coast would do more than give Canadian producers access to the vast refining markets in those areas. It would also mean surplus volumes – as crude or as refined products – could be exported to distant buyers.

Three Things
In 2009 Canada exported 1.1 million barrel-per-day into PADD 2. By the end of last year, that number had grown to 1.68 million barrel-per-day. That 580,000 barrel-per-day increase is likely to increase because of the new projects on the oilsands side that still haven’t gone on stream.

That is the bad news. The good news, according to CAPP vice president Greg Stringham, is that the markets are working hard to fix the problems. “The real key is to be ahead in building pipeline capacity, and not to be behind. Right now we’re behind, and we have seen what problems that can cause.”

“There are three things the industry is looking at,” according to Stringham. “The first is market expansion within Canada. At present we import about 800,000 barrels a day into Atlantic and Eastern Canada, even though we have a pipeline that was built in the 1970s to supply oil from Western Canada to that region.

That’s a good light oil opportunity, and there is also some potential for refining heavy oil and bitumen at the Irving refinery. In the past they did refine some oil from Venezuela. Can we get the pipeline reversed and get the oil to those markets in the medium term? The NEP is now looking at that issue.”

Would reversal of that pipeline mean lower energy costs for Canada? “The savings would be quite substantial in the short term, but that can’t last. What will happen eventually is that North American production will be priced at world oil prices.”

The biggest potential market for Canadian oil, “the 9 million barrel-per-day market,” is the Gulf coast. “We have to get into that. Right now there are many proposals to enable us to do that. The real bottleneck is the access between Cushing and the Gulf coast. That’s what’s causing the disconnect between the pricing structures in the United States compared to the rest of the world. The market is working to reverse that, by installing new pipeline capacity.”

Both Stringham and Glass are optimistic about the impact of Enbridge’s efforts to reverse the Seaway pipeline and the construction of the southern leg of the Keystone pipeline. According to Glass, “The only way we can really get our oil out is not by building refineries and trying to export product, because we simply don’t have (pipeline) access. But we can supply world markets with products by getting our oil to Gulf Coast refineries.”

On the matter of the proposed Northern Gateway pipeline, both men are effusive. “We have really strong opportunities to develop markets from Canada’s West Coast,” according to Stringham. “We aren’t only talking here about selling oil to China, but also delivering oil to other markets like California, which is currently feeding off a diet of Alaska oil, which is in decline.” A relatively new issue with this development is related to the industry’s growing need to export light and medium oil. It is no longer just a bitumen pipeline. “We need to find new markets for light oil, also. We have to find the right balance between the exports of light oil and bitumen.”

Part of finding the right balance may involve expanding the TransMountain pipeline to BC’s lower mainland – a three/four year project. That longer-term timeframe is where the biggest risks lie. How fast can Keystone XL be approved, and then how long will it take to bring it to completion? What about Northern Gateway? Reversing the TransCanada pipeline to Eastern and Atlantic Canada could also be done in the medium term, and in that timeframe it may be possible to turn part of the TransCanada gas pipeline into an oil line to Quebec.

“But looking five to 10 years out there is going to be a lot more bitumen production. We will need new markets, and those are going to require more options from (Kitimat) to California, to the East and to the farther east. Western Canada is going to need new markets. Over the next 10 to 15 years we will need to increase pipeline capacity by 1.5 to 2 million barrels a day.”

The message that Canada needs market diversification is getting a lot of traction. In a widely reported speech, Prime Minister Stephen Harper told a group in Washington that delays in the Keystone XL pipeline have greatly increased Canada’s interest in export pipelines. “We cannot be in a situation where really our one and only energy partner can say no to our energy products….The very fact that a no can be said underscores to our country that we must diversify our energy export markets.”