In a note to clients earlier this year, BMO Capital Markets urged Canadian energy companies to “merge, innovate or face extinction.”
It was advice that resonated, yet when it comes to merging, despite predictions that many small- and mid-sized explorers and producers would be forced to consolidate after energy prices slumped in mid-2014, it hasn’t happened to any great degree.
“This is what’s really strange about this downturn,” says Alicia Quesnel, an energy practitioner at Burnet, Duckworth & Palmer LLP. “It’s not acting similarly to downturns in the past. This is a much longer cycle than we’ve seen in the past, and it’s taking longer for us to come out of it. What happened in the mid-1980s and mid-1990s is not happening this time.”
He says the banks that funded their exploration and development programs in the boom years have shown “a real reluctance to push them off the cliff. It’s the old adage ‘If you borrow, you best borrow a lot, not a little.’ Because if you borrow a lot the bank really doesn’t want to crystallize a loss.”
The trend now is for banks to issue so-called forbearance agreements delaying foreclosure, he says. The agreements essentially say, “‘We’ll give you more time to get yourselves in order and we’ll wish, hope, and pray that commodity prices turn around or something else happens to enable you to continue.’ As oil and gas counsel, we’re very good these days at doing these.”
Quesnel says while the banks aren’t foreclosing, they aren’t lending to fund growth either. “That’s contributed to a fair amount of paralysis by companies who are thinking, ‘What can I do, and how can I get through this?’”
Some producers have found alternate ways of raising capital. They include selling mid-stream infrastructure, such as plants and internal pipelines, with leasebacks allowing them to continue using the facilities, or selling royalty streams — an advance portion of their production. Some are even selling royalty streams in non-producing properties in the hopes the cash upfront will be enough to bring a field online.
Canada’s oil sands are the third-largest oil reserves on the planet but the oil is also among the most expensive to produce. It’s hard to see, short of a sharp and sustained increase in prices and continued innovation bringing costs down substantially, how that will change.
Like everyone else, Canadian producers have been squeezed by the drop in the price of crude oil and natural gas, even though both have inched up this year. And oil sands producers are squeezed by the brutal transportation bottleneck in pipeline and rail, which has led some to leave product in the ground.
With 99% of Canadian exports going to the United States, they’re further squeezed on price by their largest customer — which is buying less and less.
“The US has basically exploded in terms of shale oil and gas and various Texas operations where they don’t need to import nearly as much,” says Janice Buckingham, chair of the Oil and Gas practice and co-lead of the Energy practice at Osler, Hoskin & Harcourt LLP. “They can buy our product if they need some excess to carry them over, but they’re not the big importer of Canadian oil and gas they used to be.”
The most serious squeeze Canadian oil sands companies face is the lack of a pipeline leading directly to Pacific tidewaters, which would allow Canadian crude to be loaded directly on to ships to be transported to energy-hungry countries in Asia. “One of the biggest challenges the industry has been facing is the lack of takeaway capacity,” says Buckingham. “We’ve got lots of production but we can’t get it to markets where we can get competitive pricing.
“The transportation difficulties have cast a wide shadow over the industry.”
It all contributes to The Big Squeeze: the price differential. A barrel of Canadian WCS, used to benchmark Western Canadian oil, is about $25 more expensive than a barrel of WTI, Texas light sweet, used to benchmark US oil prices.
The US imports 3.73 million barrels a day, according to the US Energy Information Administration. Canadian producers, competing with Saudi Arabia, Mexico, Venezuela and Iraq to fill that quota, are forced to discount each barrel by about $25 to be competitive.
“Part of the reluctance of investors to invest in the Canadian oil business right now has centered on that massive price differential,” says Ben Rogers, co-practice leader of the Energy and Oil and Gas group in Blake, Cassels & Graydon LLP's Calgary office.
The pipeline logjam is layered on top of that. Shipping crude by rail from the oil sands to the US Gulf Coast refineries can add as much as US$20 a barrel on to costs.
So what’s the answer? Rogers asks: “Anything that acts as a release valve to the industry.”
The best release valve, most energy lawyers agree, would be the completed Trans Mountain pipeline expansion, if the federal government manages to push it through right to the Pacific after buying it from Kinder Morgan for $4.5 billion.
Rogers steers away from the specifics of Trans Mountain because Blakes acted for Kinder Morgan on the deal; but, with the Northern Gateway and Energy East pipelines both cancelled by the federal government, he will say Trans Mountain is “the last hope” of getting more Canadian crude directly to tidewaters, at least in the foreseeable future.
Even if the pipeline expansion does get built, it will take several years. In the meantime, the oil patch has to survive, if not actually thrive.
Merge, innovate or face extinction. That was the advice.
It’s not as though there has been no consolidation, just not the type most people expected. It has come more through some large global investors exiting the oil sands, selling to Canadian companies who are doubling down on their holdings.
Royal Dutch Shell, for example, did a full retreat earlier this year, selling its stake in oil sands producer Canadian Natural Resources for $4.3 billion in a bought deal, reportedly to unidentified institutions. The sale was remarkable coming about a year after Royal Dutch Shell and Canadian Natural Resources teamed up to buy Marathon Oil’s oil sands holdings for US$2.5 billion.
Last year, Houston-based ConocoPhillips sold $17.7 billion in mainly oil sands holdings to Calgary-based Cenovus Energy. Cenovus funded the bought deal partly with 208-million Cenovus common shares, with Conoco planning to sell the stock as soon as energy share prices rebounded.
Before that, Norway’s Statoil ASA sold its stake in the oil sands to Calgary-based Athabasca Oil in 2016 for $836 million.
Canadian oil sands producers realize they have to do something about the differential, and, as the federal government fights to get a pipeline all the way to the coast, they’ve been innovating like mad to get production costs down, reportedly shaving as much as 30% off the cost of a barrel of oil.
“The industry was very good when prices fell as steeply as they did at reducing its cost structure,” says Pat Maguire, an Energy lawyer and Vice Chair of Bennett Jones LLP. “It has turned out to be far more scalable and resilient around price volatility than people gave it credit for, and most producers were able to adapt to a new price environment by focusing on their costs.”
Despite the departure of some big global names, Maguire, who is also Bennett Jones’s Calgary managing partner, says buyers are definitely still watching Canadian oil companies. “There’s far more in the works than has been announced.”
While he doesn’t see any headline-type deals in 2018, he sees mergers picking up in the junior and intermediate end. “With companies increasingly focused on core areas, they may need to consolidate to develop them.”
US private equity is still interested in Canada, he says. In June, for example, New York-based Warburg Pincus funded a management team at privately held Artis Exploration with $180 million to help the Calgary-based company develop its Duvernay shale position in Western Canada.
And there have been some early indications the banks are starting to increase producers’ borrowing bases by conservative amounts. InPlay Oil Corp. announced a credit facility hike of 25% to $75 million, while a syndicate of lenders raised Delphi Energy Corp.’s senior secured credit facility to $105 million from $95 million.
“This is hopefully indicative of a new trend,” says Quesnel of BD&P; but, despite the measures being taken, “I don’t anticipate we’ll see growth for a very many years.”
It’s much the same story for natural gas producers, says McMillan's Thackray, adding that low prices have kept companies depressed for even longer than for oil producers. “With the benchmark price so low, you’d be hard-pressed to produce it and make any money, so you’re not drilling for gas unless it’s really liquids-rich, in which case you might break even or make a profit. Drilling for oil in Alberta 200 years ago we considered gas a bit of a nuisance. We’ve come full circle.”
He says the near-term prospects for liquified natural gas, or LNG — natural gas that is turned into a liquid to make it easier to store and transport — are not much better. He says there are more than 20 wholly approved projects for the construction of LNG terminals in BC and while “occasionally we hear rumours of one or more putting shovel to the ground,” so far, no go.
He called the decision by Malaysian state-owned energy company Petronas to take a 25% stake in the potential LNG Canada project in Kitimat, BC, “a bit of encouraging news. Maybe that one’s thinking of going ahead. But the big challenge with LNG is who needs it, who wants it and who’s going to buy it?
“To the best of my knowledge, there’s no purchaser ready, willing and able," says Thackray. "Without more buyers somewhere, I’d be surprised if they actually build the facility anytime soon.”
Everything right now points to another fairly subdued year in Canada’s oil patch. But a sustained uptick in prices, or getting Canadian product directly to the Pacific for new customers, could change the outlook fairly quickly.