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.

Revolution Repeated

The Western Canada Sedimentary Basin. This article appears in the February issue of Oilweek.

By Peter McKenzie-Brown

First came the revolution in natural gas production – the shift to shale gas which, by bringing huge new stores of natural gas into the market drove prices down and made it necessary to fundamentally restructure Canada’s gas-prone petroleum sector. Now comes the revolution in the oilfield. Ironically, the same technologies that made shale gas possible are enabling the industry to begin the restructuring that the shift to shale gas made necessary.

“Oil doesn’t flow as well as gas,” Legacy Oil & Gas president Trent Yanko reminds us. “So in the oilfields of Alberta, especially, is a tremendous opportunity to recover unproduced oil. Original oil in place was in the billions of barrels, so if you can add only one, two, three percent to recovery there is quite an opportunity. You don’t have to be a wildcatter out in the jungle somewhere. All you have to do is better exploit what we already know is there.”

The technologies that made the shale gas revolution possible are beginning to have a similar impact in the light and conventional oil sector, which can now develop reservoirs that could not be exploited until energy prices and new technologies made production economic. For small companies in particular, this is presenting exceptional opportunities. From start-ups to mid-caps, companies like TriAxon and PetroBakken Energy are creating profitable enterprises from oilfields discovered 50 years ago. Already successful in similar enterprises, Legacy is taking on the big kahuna – the century-old field that put Canada’s petroleum headquarters on the map.
Juniors and the Treadmill

Since it became commonplace in the late 1980s, horizontal drilling has been enhanced by increased drilling efficiency. Much longer horizontal legs are now possible: many are two and three kilometres in length. This is possible because of improvements in bit design, the increasingly effective use of coil tubing and better down-hole motors. Other contributors include geo-steering and increasingly effective measurement-while-drilling (MWD) tools and techniques. Most important of all is multi-stage fracturing. The industry can now isolate many completion zones along lengthy horizontal wellbores: a two-kilometre horizontal leg can host up to 20 hydraulic fractures.

These technologies are making formations like the Bakken viable. Increasingly, the technologies that created the shale gas revolution – long horizontal wells and multistage fracturing – are being applied to aging light oil reservoirs in North America. This production phenomenon has also involved largely unacknowledged regulatory responses by the governments of Western Canada. These factors and other technologies are opening up important new opportunities for production from largely depleted reservoirs. For example, Gary Leach – executive director of SEPAC (the Small Explorers and Producers Association of Canada) – notes that “microseismic for the more precise design of frac jobs is a particularly important new technology.”

A year ago, TriAxon Resources represented a big success story among private junior oil companies. The company was created with what in 2006 was the novel idea of applying the cluster of new technologies to oil production. After screening available prospects, the company focused on the Bakken, Glauconite, Cardium, and Viking formations. The company raised $87 million in private financing; two and a half years later the partners sold out to Crescent Point Energy for $257 million.

Then, according to former president Jeff Saponja, he and his two partners – chief operating officer Colin Flanagan and operations vice president Rob Hari – took a two-week break before establishing TriAxon Oil Corp. – “TriAxon Two,” he calls it.

The opportunities come with a cost, of course. Saponja cautions that those technologies present unique challenges because they are so capital-intensive they. “Fifteen years ago, in the heyday of conventional oil exploration and production, you would put $150,000 to maybe $500,000 into the ground to get 200,000 barrels of oil,” according to Saponja. “Now you have to put maybe $4 million in the ground to get 200,000 barrels of oil, and you have a 50% to 80% initial rate of decline. To get these multistage frac wells to work you have to drill a lot of wells in these lower quality reservoirs.” This leads to what he calls the treadmill.

“To offset decline you have to be continually drilling, because the decline rate is so high. The main point of the equation is that these horizontal wells are very capital-intensive. Initially you get a very high rate of oil production but they will decline quite quickly. The economics are actually fairly marginal on a well to well basis, so you have to drill a lot of wells to benefit from scale. Except in the Bakken,” he says, “Most of these multistage frac wells really struggle if oil prices are below $60 or $70. For these wells to be really profitable, oil has to be over $80 a barrel.”

“You have to be continually drilling to offset decline. It’s called the treadmill. The main point of the equation is that these horizontal wells are very capital-intensive. Initially you get a very high rate of oil production but they will decline quite quickly. The economics are actually fairly marginal on a well-to-well basis, so you have to drill a lot of wells to benefit from scale. Except in the Bakken,” he says, “Most of these multistage frac wells really struggle if oil prices are below $60 or $70. For these wells to be really profitable, oil has to be over $80 a barrel.”

Does it make sense for private companies like TriAxon to stay public? According to Saponja, the economics of staying private are iffy. “These are very expensive wells. For a junior to stay on the treadmill becomes very difficult after you reach 3,000 or 4,000 barrels a day because you need a lot of capital to grow production and combat decline. The challenge that juniors face is that they have to either get their hands on more capital or be prepared to monetize their assets by selling them off. That’s the case for going public: it gives you access to low-cost capital. However, my partners and I are happy building basements, then selling them to the highest bidder.”

Midcaps in the Bakken
The highest bidder for TriAxon One was Crescent Point Energy – one of the two largest players in the Bakken, and the main competitor of PetroBakken, a midcap headed by Gregg Smith. “Our decline rates in the Bakken are about 60% in the first year, so we have to keep drilling to maintain production rates. You have to experiment a lot to be successful in plays like this. When you come into these plays your initial results are going to be mixed, but as you refine your drilling and production systems they improve.”

With considerable satisfaction, Smith notes his company’s success in drilling bilaterals from a single wellpad. “For PetroBakken to drill a single horizontal, the cost is $2.4 million. However, to drill two bilaterals from a single pad costs $3.6 million. It’s much more capital-effective, and it delivers an extra 50,000 barrels per well into the bargain.”

According to SEPAC’s Leach, the obviously improved economics of tighter spacing is generating “a regulatory response. The design of wellpads has to be different, and the new wellpads provide both environmental and economic benefits. Regulators are beginning to respond in all three western provinces.”

He adds, “The Cardium just began to take off in early 2009, and it was SEPAC companies – junior and midsized companies – that set the stage for this. Those sectors are looking to restructure because of the long-term poor prospects for natural gas, and this has played a role in that. It’s really turned around the fortunes of the industry, and generated a lot of investor interest.” With some satisfaction, he notes that multinational companies are coming back to North America to get back into the light and conventional oil resource plays. This involves a turnabout for some companies. for example, Talisman sold off a lot of its Alberta oil production just a few years ago.

PetroBakken’s Smith stresses that the situation in Canada is quite different than that in the United States. The Americans “are drilling shale oil plays. (By contrast) most of the horizontal wells with multistage fraccing in Canada are into reservoirs that were previously simply uneconomic or marginally economic (if you were trying to produce) oil from a vertical well.” This is all changing now, he says. “Now you’re seeing people try to tie up shale oil plays like the Alberta Bakken, the Duvernay and the Nordegg.”

Back to the Future
Of course, old hands in the oil industry are the first to tell you that technology has always been the key factor in expanding production. In fact, in this period of oilfield revolution the importance of technology is more obvious than ever before. According to Legacy president Trent Yanko, “Technology has always been an important part of oilfield development in Canada. I started out in Saskatchewan in 1980s, which was really Canada’s leader in horizontal drilling because of a major government incentive program.” After a few years the industry found itself drilling more horizontals in Saskatchewan than anywhere else in North America – “even the Austin Chalk” in Texas.

“Southeast Saskatchewan has been a classic case of the use of technology to extend the life of reservoirs,” Yanko continues. “Since the 1960s the industry has applied waterflood there, horizontal drilling, CO2 injection and other technologies, each of them extending the life of the province’s south-eastern petroleum reserves. As a result, in the late 1990s oil production matched what everybody thought had been the peak oil levels of 1966, and today the province is at record production.”

Almost all of the reservoirs now being developed with these technologies were discovered after 1947, when the Leduc discovery ushered in the industry’s modern age. Yanko, however, has plans to apply them in the petroleum industry’s birthplace. “Through the acquisition of a private company in July,” he says, “we acquired the Turner Valley oilfield. We control most of the production and all the facilities there.”

To understand Turner Valley’s significance, it’s worth noting that the field’s proximity to Calgary is the reason Canada’s petroleum sector is headquartered in the city. And, as SEPAC’s Gary Leach observes, Calgary now hosts the 45% of the world’s publicly traded oil and gas companies.

As he discusses this property, Trent Yanko becomes palpably excited. “There is still a lot of meat on the bone. There’s been less than 1% decline in (annual) oil production (from Turner Valley) over the last fifty years. The original oil in place was 1.3 billion barrels of 40° oil, and the historical recovery factor to date is only about 12%. So we think it has huge development potential. Before we acquired the property, the last vertical wells were drilled there in the 1940s. There was some horizontal drilling in the 1990s, but the field has been non-core for a long time.”

Although Legacy is proceeding cautiously, its president is thinking big. To begin with, Yanko believes Legacy has mapped a Cardium trend right on top of the field – “11 miles long and about 1½ miles wide,” with 10 metres gross maximum thickness. “In Turner Valley there’s a vertical well that just missed the Cardium and still produced more than 19,000 barrels. Otherwise, that trend hasn’t even been touched.”

“We believe the application of horizontal drilling and multi-stage frac technology can increase the recovery factor,” he adds. “So can infill drilling and reactivation of the waterflood. This property hits a lot of our hot buttons.” In the fall, the company drilled a number of vertical wells into the field. “We are going to frac them, and they will provide a great controlled environment to help us understand the horizons for future horizontal drilling. These wells will help us design that drilling program properly.”

When Turner Valley was first drilled in 1913, it was a wet gas field from which liquids were extracted and natural gas flared. A century later, with conventional gas again a marginally economic commodity, the prize sought in Turner Valley reservoirs is again its hydrocarbon liquids. The difference today is the toolkit.