A lack of pipelines is hitting the Canadian energy sector hard these days – and not just in the oil sands.
Infrastructure bottlenecks have long been the bane of Alberta’s heavy crude sector, but limited export capacity is now causing headaches across the energy industry. Companies that produce light oil and other gas-related liquids have recently seen their prices decline compared with what competitors in the United States are able to command.
That slump is eroding the benefit that western producers enjoyed from the rise in global crude prices this year, and is reinforcing the view that Canada is forgoing billions of dollars of energy revenues that would go to both industry and government.
Calgary-based Modern Resources Inc. is one example of a company whose ambitions are being stymied by a shortage of pipeline capacity needed to get Alberta’s growing oil and gas production to markets.
Formed six years ago, Modern focuses mainly on low-cost natural gas production in Alberta’s deep basin. It also produces liquids such as light oil and condensates such as propane and butane. Its oil and condensates have provided growing cash flow at a time when gas prices have been in a prolonged slump.
With gas prices low and its liquids business taking a hit, Modern’s chief executive said cash flow is 40 per cent below target for 2018, and as a result its capital budget is getting squeezed and its drilling program has been curtailed.
So far, Modern has been able to secure space on pipelines to get its liquids to markets, but it may soon face restrictions, CEO Chris Slubicki said.
“Our pipeline constraints in Canada – whether on natural gas or oil – are a self-imposed financial penalty, similar to a tariff,” Mr. Slubicki said. “We have to get beyond this. We have to get building again.”
Frustration over the lack of pipeline construction has reached a fever pitch in Alberta, especially after the Federal Court of Appeal in August quashed Ottawa’s approval of the Trans Mountain pipeline expansion. The project – which the federal government insists will proceed – would increase the shipment of oil sands bitumen to the Vancouver harbour by nearly 600,000 barrels a day and open new Pacific Rim markets for landlocked Alberta.
The price for oil sands crude has fallen close to multiyear lows, battered by a combination of pipeline constraints, surging production in northern Alberta and maintenance at big refineries in the United States.
The difference between benchmark West Texas Intermediate (WTI) and Western Canadian Select (WCS) widened to a near-record US$35 earlier this month, and stood at US$33.75 the end of last week. That means Alberta heavy oil is worth about half as much as WTI, which closed at $70.78 last week.
Edmonton Par blend – a benchmark for lighter crude – was selling at just a few dollars less than WTI last year but that differential has widened to US$17.03 as of Friday.
Premier Rachel Notley argues the industry’s inability to fetch world prices costs Canada some $15-billion in lost revenue this year, though that claim has been challenged by some industry critics.
In defending the figure, Ms. Notley points to a report from the Bank of Nova Scotia that first used the estimate back in February, when the difference between WTI and WCS – also known as the light-heavy differential – climbed above US$30 a barrel. Canadian heavy crude typically fetches a lower price than WTI based on quality differences and higher transportation costs, but that discount got bigger as pipeline constraints and other factors affected the market.
Scotiabank economist Rory Johnston said the $15-billion price tag was an estimate of the amount of revenue that would be lost to the upstream oil business if the differential had stayed above US$30 for all of 2018. Instead, it shrank back closer to US$20 before expanding again in recent weeks.
Mr. Johnston estimates the yawning light-heavy differential – plus widening discounts on lighter crude – could cost the upstream oil industry roughly $12-billion this year.
While U.S. refiners tend to be the big winners by purchasing discounted Canadian crude, some of the $12-billion is recycled through the Canadian economy, Mr. Johnston said. Railway companies, notably Canadian National and Canadian Pacific, are taking a cut through fees to move increasing quantities of crude.
As well, integrated oil companies such as Suncor Energy Corp. and Imperial Oil Ltd. can recoup some foregone revenue on the production side of the business when they refine the crude and sell products such as gasoline and diesel into a market that is typically based on world oil prices.
Suncor, for example, said only 20 per cent of its crude production is vulnerable to the steep light-heavy discounts. The company upgrades bitumen into synthetic crude, which typically sells at a premium to WTI; it processes discounted heavy crude at its refineries and makes added profits on that downstream business and it is able to ship some of its bitumen to “locations attracting global heavy prices,” the company said in a presentation this summer.
Economist Robyn Allan said the major oil sands companies, in particular, have a number of hedging strategies that allow them to minimize their exposure to the differentials.
“It is very important to remember that in examining the differential there are a number of supply and demand factors that play out at each stage of the supply chain,” said Ms. Allan, who has been active in opposition to the Trans Mountain project.
“Most of the analysis we have seen only looks at pipeline capacity and this is not only naive but provides false conclusions.”
Still, lower prices mean less revenue reinvested in future production in western Canada, and lower royalties and taxes paid to provincial and federal governments, though there is no firm estimate for how much revenue governments might lose.
Based on futures prices for 2019, ARC Financial Corp.’s Energy Research Institute expects a 10-per-cent drop in capital expenditures in the upstream part of the energy sector, as a result of the change in cash flow related to lower commodity prices.
“We’re definitely suffering from a lack of take-away capacity relative to our supply,” ARC economist Jackie Forrest said. Refinery shutdowns in the United States normally cause weaker prices in Canada, she noted. “But because of our takeaway capacity and growing supply, it just amplifies it.”
It will be at least a year before that pipeline capacity eases, though railways are promising to boost their ability to carry crude. The completion date for Trans Mountain’s expansion is up in the air, but will likely be after 2020.
A workman walks past steel pipe to be used in the oil pipeline construction of Trans Mountain project in Kamloops, B.C., May 29, 2018.Dennis Owen/Reuters
The one bright spot: The pipeline company Enbridge Inc. is proceeding with its Line 3 expansion, which will add 375,000 barrels a day of capacity on the main export line into the United States. It should be completed in late 2019 or early 2020.
Meanwhile, producers are expected to add another 160,000 barrels a day of output in both 2019 and 2020, according to the Canadian Association of Petroleum Producers. That’s on top of 360,000 b/d that is coming on stream this year.
At this point, producers and refiners are scrambling for pipeline space. Enbridge has announced apportionment on its main line to the United States, meaning companies can’t get all the space on the pipeline they require. For Line 3, individual shippers may only get 56 per cent of the pipeline capacity that they ask for.
“A lot of people are fighting for available pipeline capacity,” Scotiabank’s Mr. Johnston said. “If the crude doesn’t end up on a pipeline, it goes to rail and if it doesn’t end up on rail, it ends up in inventory. So we’re really running out of places to put it.”
Major companies are now faster to curtail production or schedule maintenance work at plants to coincide with periods of weak prices. Earlier this year, Cenovus Energy Inc. lowered output at its two steam-driven projects, an extraordinary measure to cope with what the company called a “critical” shortage of export pipeline capacity.
The process involves turning down pumps and letting sticky crude pool in reservoirs, withholding barrels from the market until congestion on pipelines clears and prices firm up, said Drew Zieglgansberger, executive vice-president of upstream operations.
“We wouldn’t need to use it if we could see that we were getting fair value for our oil,” he said. “We would want to ship it to market, because the demand is there.”
With files from Jeff Lewis