For years, we’ve been told again and again (and again) that Kinder Morgan’s proposed expansion of the Trans Mountain pipeline is desperately needed for producers to export oil to Asian countries and get much higher returns.

The way it’s been framed makes it seem like it’s the only thing standing between Alberta and fields of gold.

Small problem: Canadian producers already have the ability to ship their heavy oil to Asia via the existing 300,000 barrel per day Trans Mountain pipeline — but they’re not using it.

“Virtually no exports go to any markets other than the U.S.,” economist Robyn Allan told DeSmog Canada. “The entire narrative perpetrated by Prime Minister Trudeau and Alberta Premier Notley is fabricated.”

In 2017, the Port of Vancouver only shipped 600 barrels of oil to China. That’s less than a tanker load. That same year, the port shipped almost 13 million barrels of oil, or about 24 Aframax tanker loads, to the U.S.

In other words: oil tankers are being loaded in Vancouver, but instead of heading to vaunted Asian markets, they’re heading south to California.

Shipments to Asia reached their peak seven years ago when the equivalent of nine fully loaded tankers of oil left Vancouver for China. Since then, oil exports to Asia have completely dropped off.

Some experts suggest exports to Asia are very unlikely to rebound in the short-term, with producers from many other countries continuing to dominate such markets. Others take a more long-term view, remaining optimistic that opportunities will arise over time — and only after the pipeline is actually built

“There’s no appetite in Asia for heavy oil,” said Eoin Finn, former partner at KPMG, in an interview with DeSmog Canada. “They don’t have the refineries to refine it. And the world is swimming in light sweet crude that’s cheaper and easier to refine, and altogether more plentiful.”

“There’s no appetite in Asia for heavy oil. They don’t have the refineries to refine it. And the world is swimming in light sweet crude that’s cheaper and easier to refine, and altogether more plentiful.” https://t.co/XCN92a02eS

— DeSmog Canada (@DeSmogCanada) April 19, 2018

No guaranteed access to Asian markets

One challenge is that the Port of Vancouver can’t even physically fit the size of tanker required to economically compete with other shippers of oil to Asia.

The largest class ship that is allowed in Burrard Inlet is what’s known as an “Aframax.” It can only be filled to 80 per cent capacity due to depth restrictions. That means a tanker from the Port of Vancouver can only ship 550,000 barrels at a time.

Meanwhile, Very Large Crude Carriers — yes, that’s actually their name — are now embarking from Louisiana via its brand new port, carrying two million barrels each. They’re also used by many Middle Eastern producers.

Practically, this means that Trans Mountain will have a harder time competing with producers in countries that can pay far less to ship their cheaper-to-refine oil in much larger ships. Trans Mountain supporters suggest this could become quickly irrelevant if situations change: say, a war breaks out in the Middle East and takes millions of barrels per day offline.

There’s also no guaranteed demand for Alberta’s lower quality crude on the other side of the Pacific. While 13 producers and shippers have signed long-term contracts with Trans Mountain — a fact that’s leaned on heavily by the company to make its business case, as they represent 80 per cent of expanded capacity — none have buyers in Asia yet.

“It’s a bit of a chicken and egg scenario. You need to build that pipeline before people are going to spend billions of dollars configuring their refineries to take your crude,” Jackie Forrest of ARC Energy Research told the CBC in a 2017 interview.

It’s expected that “sample shipments” of oil would be sent to various markets for testing once the pipeline was built.

But there’s very little proven interest in Alberta’s hard-to-refine oil. Instead, Asian countries are continuing to rely on imports of light sweet crude from Middle Eastern locales like Saudi Arabia, the United Arab Emirates, Iran, Qatar and Iraq. At this point, that appears unlikely to change in a significant enough way to make Alberta oil competitive.

Price discount results from lack of capacity, not location

The reality is that Alberta oil will always sell at a discount to lighter crude with greater market access.

In fact, back in 2014 a vice-president at the Canadian Association of Petroleum Producers told the Toronto Star that “there’s always a natural discount in the range of $15 to $25 [per barrel].”

In recent years, the “discount” has hovered around $10/barrel.

Nothing about a new pipeline will change the fact that Alberta’s heavy oil takes more effort to refine into usable products and is located farther from major markets than most other sources.

“It’s the lack of pipeline capacity that creates the price discount for Alberta. It’s not where that pipeline capacity goes. It’s not the difference between the U.S. Gulf and Asia,” Tom Gunton, professor and director of Simon Fraser University’s resource and environmental planning program, told DeSmog Canada.

“It’s got to do with that there’s not enough pipeline capacity.”

When Trans Mountain was pitched in 2013, there was a legitimate shortage of pipeline capacity, a reality made more concerning to industry by massive production forecasts for future decades. It seemed like an imminent and long-term backlog was about to emerge — which would actually lead to a price discount.

But then the 2014-15 price crash happened, new pipelines came online and dozens of proposed oilsands projects were either scrapped or put on hold.

When former U.S. president Barack Obama’s vetoed TransCanada’s Keystone XL pipeline in 2015 the backlog idea began gaining traction once again. But the veto has since been rescinded by President Donald Trump.

Gunton said that if you combine Keystone with Enbridge’s Line 3 and the proposed Mainline expansion, “there is more than enough pipeline capacity to meet all of Alberta’s needs without Trans Mountain” meaning that no serious price differential will emerge.

TransCanada spill in South Dakota responsible for current discount

The main reason that Alberta is currently experiencing a larger differential than usual (around $25/barrel) is because TransCanada’s Keystone pipeline spilled almost 10,000 barrels of oil into a South Dakota field in November — the third incident from the pipeline since 2010.

That resulted in a two-week shutdown, and the pipeline has been running at 20 per cent reduced pressure ever since.

As Allan pointed out in a letter to the Calgary Herald, this means that around 120,000 barrels per day have been backlogged, accounting for the widening differential. You can basically see the moment when the spill happened on differential estimations, increasing from $11/barrel in November to $25/barrel in February.

It is not a lack of market access to Asia that gutted returns for oil companies — it’s a pipeline spill. The phenomena of spills squeezing pipeline capacity is something Allan has previously documented.

Gunton said that even the two reports submitted by Kinder Morgan to the National Energy Board — the first of which was striked as evidence after its author, Steven Kelly, was controversially appointed to the regulator — didn’t identify an “Asian premium.” Instead, they argued that some of the shipments out of Alberta would have to go by rail due to inadequate pipeline capacity, reducing netbacks to producers. That’s no longer true.

“That’s another big lie that there’s this big demand in Asia,” said Green Party leader Elizabeth May. “There’s this series of assumptions that are repeated so often that nobody questions them.”

Most expanded capacity will end up in California, not Asia

But while politicians like Rachel Notley continue to repeat the fiction “that there is now and will always be a pretty substantial market for bitumen in the Asia-Pacific” many analysts have identified that most oil shipped from the expanded Trans Mountain line via Vancouver (with a significant chunk already diverted in Abbotsford to Washington refineries) will end up in California in the short term.

A 2013 report from the University of Calgary’s School of Public Policy argued: “Movement of crude supplies originating in Vancouver should satisfy U.S. West Coast demand before the first barrel crosses the Pacific to Asia.”

This is mostly because California is facing declining domestic production and imports from Alaska’s North Slope. Additionally, it already has refineries in place to process heavy oil, and Albertan bitumen could directly compete with Mexican Maya, a similar quality crude.

Based on 2017 data, only 3.4 per cent of California’s foreign crude imports came from Canada. That same year, half of the state’s imported oil came from Saudi Arabia, Ecuador and Colombia — which can all produce at far lower costs than Alberta. The state’s Low Carbon Fuel Standard also rewards crude oil with lower carbon intensity, further benefiting OPEC exporters over Alberta.

“There’s no premium to go to California,” Finn said. “There’s probably a discount because it’s farther and costs more to have ships go down there.”

U.S. Gulf Coast remains most lucrative location

So where is Alberta’s slowly-but-surely increasing oil production supposed to go? Well, where it’s always gone — to the U.S. Gulf Coast, aided by TransCanada’s Keystone XL and Enbridge’s Line 3 pipelines.

Compared to shipping via tankers from Vancouver, the Gulf offers comparatively cheaper transportation fees and existing heavy oil refining capacity.

In addition, both Venezuela and Mexico’s heavy oil production have also been in steady decline in recent years, providing even more potential for Alberta to fill existing refinery capacity in the Gulf.

“As we implement climate policies and as the world transitions away from fossil fuels, production in Alberta is not going to grow very much,” Gunton said.

“It’s the highest-cost producer in the world. Consequently, the demand for pipelines is down. And there is more than enough pipeline capacity to meet all of Alberta’s needs without Trans Mountain.”

Economic circumstances have shifted dramatically since 2013 when Kinder Morgan first proposed the pipeline, which raises the question: does the company want to back away from the project for reasons that stretch beyond the opposition its facing in British Columbia?

Even with both the Alberta and federal governments discuss bailing out the private project, in an investor call on Tuesday, Kinder Morgan indicated the investment may still be “untenable.”

If the company walks, a government could either purchase the $7.4 billion project as hinted at by Premier Notley. Or, Kinder Morgan may opt to sue the Government of Canada via NAFTA.

Whatever happens, one thing seems certain at this stage: it’s not going to be predictable.

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The NDP government’s arithmetic on Site C cancellation costs is “deeply flawed,” has “no logic at all,” and is “appalling,” according to three project financing experts.

Eoin Finn, a retired partner of KPMG, one of the world’s largest auditing firms, said Premier John Horgan’s claim that terminating Site C would result in an almost immediate 12 per cent hydro rate hike is the “worst rationale I’ve heard since ‘the dog ate my homework’” excuse.  

“I expected better when the new government came in,” said Finn. “They’ve just continued what [former premier] Christy Clark did to hide the true costs of Site C and hope that they get re-elected before the next generation finds out.”

“This is the stupidest capital decision ever made by a B.C. premier. I don’t know who is giving them accounting advice.”

Rob Botterell, legal counsel for the Peace Valley Landowner Association, representing 70 landowners who will lose homes and property to the Site C dam, called on the NDP government to disclose who advised Cabinet on hydro rate increases in the event that Site C were terminated.

“We call on you and your colleagues in Cabinet and Caucus to publicly release the detailed, un-redacted, information and advice and analysis on which you based this finding,” Botterell wrote to Attorney General David Eby and Environment Minister George Heyman.

On Thursday, the landowner association and the Peace Valley Environment Association hand-delivered a letter to B.C. Auditor General Carol Bellringer, asking her to launch an “urgent examination” of the government’s Site C termination and completion cost figures.

The letter also asked Bellringer to verify the cash impact of both scenarios on British Columbians.

The Auditor General’s office was in the midst of investigating Site C’s finances last summer when the new NDP government asked the watchdog B.C. Utilities Commission to review the project, which will flood the traditional homeland of Treaty 8 First Nations, violate basic human rights, force farming and ranching families from their homes, and destroy critical habitat for rare and endangered species.

The BCUC review disclosed that Site C is over budget, behind schedule, beset with geotechnical issues and embroiled in legal and financial challenges with its main civil works contractor, which lost its Canadian partner earlier this year when Petrowest Corporation slid into receivership.

NDP Not Following Standard Accounting Practices, Experts Say

Horgan told reporters Monday that the only recourse if Site C were cancelled would be to hit BC Hydro customers almost immediately with a 12 per cent rate increase to cover the project’s $2.1 billion in sunk costs and $1.8 billion in reclamation costs.

But Finn, along with U.S. energy economist Robert McCullough and Harry Swain, a retired bank president with expertise in project financing, told DeSmog Canada that standard accounting practice for utilities like BC Hydro is to write off the costs of a discontinued project over many years.

“What’s appalling about this is that Cabinet has been advised by some people who simply don’t understand how the finance system works,” said Swain, the former CEO of Hambros Canada Inc. and a former board member of Hambros Bank Ltd. of London.

“I can’t believe that their arithmetic is that bad,” said Swain, who chaired the Joint Review Panel on Site C for the federal and provincial governments. “It’s all very depressing.”

McCullough, a former officer for a large hydroelectric facility in Portland, Oregon, said Site C’s sunk costs — mainly accrued as former Premier Christy Clark attempted to push the project past the “point of no return” — can be amortized over the 70 years that Site C was expected to produce electricity, in keeping with standard procedure for North American utilities.

“Ratepayers should not be punished for the utility making the correct policy decision, and nor would they be in any normal circumstance,” said McCullough, who was hired by the Peace Valley Landowner Association to provide expert testimony for the BCUC review.

“It’s not at all unusual for a project to stop and start for good reason,” McCullough said, adding that one common reason for terminating an energy project is a change in policy.

Swain said Site C’s sunk costs could be paid off over 30 years “without any heavy breathing at all.”

Finn called the government’s claim that terminating Site C would immediately incur up to $150 million a year in new debt service charges “pure financial fiction,” pointing out that BC Hydro has already borrowed the money and is paying interest on it so cancelling Site C will not make any difference.

“What’s appalling about this is that Cabinet has been advised by some people who simply don’t understand how the finance system works.” https://t.co/ExRvtuoFKn

— DeSmog Canada (@DeSmogCanada) December 15, 2017

What About Site C’s Reclamation Costs?

McCullough said the reclamation costs could be dealt with swiftly if the government declared the disturbed area of the Peace River Valley a park, making it a provincial asset and removing remediation costs from Site C’s books.

The cost of remediating the valley area already disturbed by clear cutting and bull-dozing for Site C is a matter of contention.

West Moberly First Nations chief Roland Willson has said the NDP’s stated $1.8 billion reclamation cost is greatly exaggerated. He urged BC Hydro and the government to make Site C’s construction site safe and “go home,” allowing natural regeneration of the boreal forest.

Even assuming that $1.8 billion in reclamation costs is factored into the equation, cancelling Site C will result in a 4.9 per cent hydro rate hike starting in 2024, McCullough said.

But that compares very favourably to the 12.4 per cent rate hike that will hit hydro customers that same year if Site C continues, he pointed out.

And that’s top of 30 per cent hydro rate increases already projected by the NDP government over the next 10 years, and also assuming that Site C’s cost does not escalate further.

Site C was announced as a $6.6 billion project in 2010. The price tag jumped to $7.9 billion by 2013, then to $8.8 billion in 2014.

On Monday, the NDP government revealed that the cost has soared to $10.7 billion just two years into a nine-year construction schedule, raising questions about whether Site C will become a boondoggle like Labrador’s Muskrat Falls dam, which will add an average $1,800 to the annual hydro bills of every household in that province.

What Happened to That Independent BCUC Oversight?

The NDP continues to criticize the former Liberal government for failing to send Site C to the BCUC for review before it decided to proceed with the Peace River project.

Yet, according to the three project financing experts, Cabinet neglected to follow proper procedure and allow the BCUC — an independent regulator that makes decisions based on the best financial interests of hydro customers — to decide how Site C’s termination costs could be best distributed to avoid a rate shock.

Swain called the matter an “ordinary regulatory decision,” while Finn said it is “not the government’s business” to decide how Site C’s termination costs would be allocated.

“The government has no right to make that judgment,” said Finn, adding that the only way Cabinet can override BCUC oversight is to pass an Order in Council.

“They’re side-stepping the legal obligation under the Utilities Act to involve the BCUC. They never asked the B.C. Utilities Commission.”

Horgan’s office confirmed to DeSmog Canada on Thursday that Cabinet did not pass an Order in Council.

In puzzling logic, Eby said in a public statement on Thursday that the recovery period for Site C’s costs would only be subject to an independent BCUC review “if, and when these costs are incurred,” meaning that the BCUC would only be able to make that decision after Cabinet decided to cancel Site C.

McCullough, whose testimony to a U.S. Senate Committee helped spark the criminal investigation into Enron, said recovery of an energy project’s termination cost is “a very common practice in the utility business and is addressed in every utility’s annual report.”

What About B.C.’s Credit Rating?

McCullough also pointed out that B.C.’s triple A credit rating has just been confirmed.

Contrary to statements made by the NDP, cancelling Site C does not put the province’s credit rating in jeopardy because Site C’s sunk costs have already been financed with 30-year bonds, he said.

On the other hand, spending at least $8 billion more to complete Site C when its power can be replaced for only $4 billion, “may concern the bond raters,” McCullough wrote in a December 11 memorandum for the landowner association.

He pointed out that the same issue was a factor in the downgrading of Newfoundland and Manitoba’s credit ratings as both provinces grappled with huge cost overruns on large hydro dam projects.

“Even if the inflated $1.8 billion in termination costs are added, cancelling Site C will save ratepayers at least $266 million [a] year or $123 [per] household in 2024,” McCullough wrote in comments the landowner association submitted to Bellringer’s office.

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The spectre of a massive, floating LNG plant in environmentally fragile Saanich Inlet may seem unlikely to gain environmental approval, but the proposal must be defeated before liquefied natural gas prices increase to the point that the project becomes too tempting, worried southern Vancouver Island residents are being warned.   “It is best not to let your guard down and say the economy is not good right now,” said Eoin Finn, founder of My Sea to Sky and a retired partner in KPMG, who holds a PhD in physical chemistry.   Proposals by Steelhead LNG Corp. for a floating plant anchored adjacent to Malahat First Nation land at Bamberton, fed by gas pipelines criss-crossing the Salish Sea and then snaking across Vancouver Island to Sarita Bay near Bamfield, where the company wants to build a larger LNG plant on Huu-ay-aht First Nation land, were initially greeted with incredulity.   However, last October, the National Energy Board approved export licences for Steelhead to export up to 30 million tonnes of LNG per year for 25 years, with six million tonnes from Malahat and the remaining 24 million tonnes from Sarita Bay.

There are currently 20 proposed LNG projects in B.C. although none have received final investment decisions. Three projects, including LNG Canada in Kitimat, Pacific Northwest LNG near Prince Rupert and Woodfibre LNG near Squamish, have advanced beyond the proposal stage but a combination of low prices, First Nations opposition and federal permitting have prevented the industry from gaining a major foothold in the province.

“The NEB seems to hand out export permits like confetti at a wedding,” Finn told capacity crowds at meetings in Esquimalt and Mill Bay.   It is not only the Steelhead plant itself — which would be the first floating LNG terminal in the world — that should worry southern Vancouver Island residents, they should also consider the massive ships, about the length of three football fields, that would pick up LNG, Finn said.   The ships suck in vast amounts of seawater to cool the frozen gas, which means phytoplankton and small fish are also sucked in, making “the biggest bouillabaisse engine of all time,” Finn said.   “Then they blow it out again and, because they don’t want anything fouling the pipes of their very expensive ship they add a little biocide into it,” he said.

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“That means 50,000 tonnes of hypochlorited hot water poured into the Inlet every year, making it into a marine desert.”   Or, think about the greenhouse gas emissions, Finn suggested.   “It would be like adding 400,000 cars a year to the Malahat.”   Saanich Inlet, a glacially-carved fjord with deep water that is oxygen-depleted for much of the year, has been studied by scientists for 80 years because of the rare ecosystem that produces phytoplankton blooms. It is home to shellfish, herring, salmon and many other species and currently houses the Ocean Networks Canada VENUS (Victoria Experimental Network Under the Sea) cabled undersea laboratory.

VENUS Laboratory in the Saanich Inlet. Photo: Ocean Networks Canada.   It is flanked on one side by the winding Malahat highway, dotted with numerous small communities, and on the other side by Saanich Peninsula, with villages such as Brentwood Bay, tourist attractions such as Butchart Gardens and Victoria International Airport. At the tip of Saanich Peninsula is the busy Swartz Bay Ferry Terminal.

Steelhead CEO Nigel Kuzemko said one of his priorities is ensuring that there will be no detrimental effects on Saanich Inlet, so the company has commissioned a study that will model the effect of one LNG ship a week picking up gas from the floating plant.   Using seawater for cooling the giant LNG thermos tanks is more efficient than air and will produce less greenhouse gas emissions, he said.   “But the water comes out warmer which is what we are concerned about and we want to know what the effect will be on Saanich Inlet,” Kuzemko said.   A chemical will be used to stop bacteria growing in the pipes, he said.   “We are looking at different ones, but they will all be biodegradable so they don’t have any long-term impact,” he said.   Saanich Inlet is a unique area, but has had its share of industrial activity over the last 100 years, Kuzemko said, pointing out that the area where the plant would be situated is beside the old Bamberton concrete plant, where the bottom of the Inlet is covered in concrete dust.   Information compiled in the study would be needed for the environmental assessment process, but Steelhead wanted to get out in front and ensure all the questions were answered and that the community had been consulted from the start, Kuzemko said.   “We hope to do it the right way, but, some people think any energy project is wrong,” he said.   “What we are trying to do is something that we think is great for the world. There’s no reason industry and Saanich Inlet can’t co-exist.”   The aim of reducing the environmental footprint is the reason Steelhead has chosen to use existing pipeline routes, meaning the route wends from B.C., across the Strait of Georgia to Washington and then back to Saanich Inlet, rather than cutting across an untouched landscape over the Coast Range mountains, Kuzemko said.

Adam Olsen, B.C. Green Party deputy leader, who lives 100 metres from Saanich Inlet and grew up on Saanich Peninsula, fears that the belief such a proposal will automatically be rejected is resulting in apathy, which could allow Steelhead to slip through the approval process.   Even though the project is unlikely to be viable at the current price of LNG, many options open up once the company is given a certificate, he said.   It could be sold or put on stand-by for the future, so the focus has to be stopping it at this stage, said Olsen, who believes the provincial government is likely to be in favour.   “This government has basically bet everything they have on LNG and they are also the regulator,” he said.   “I don’t think we can have any confidence that, just because the project appears to be outrageous, that this government won’t look at it seriously.”   Olsen is a member of Saanich Inlet Network, a group formed to fight the LNG proposal, which, during the last week, has collected almost 500 signatures on a petition asking provincial Environment Minister Mary Polak and federal Minister of Natural Resources Jim Carr to reject the Malahat proposal.   Investigative energy reporter and author Andrew Nikiforuk, who has written extensively on LNG, worries that, if Steelhead builds the plants, there will be a push to extract methane from the many coal seams around Vancouver Island.   “A company which has spent billions on LNG terminals will want to keep those facilities full and there’s a lot of methane in old coal seams on the Island,” he said.   “It could mean fracking in watersheds full of salmon.”   However, Finn believes that using methane from coal seams would not be tolerated even if the company is given approval for the plants.   “The coal seams are very close to the surface and any government that gave a company the right to frack so close to people’s drinking water would be hung, drawn and probably quartered,” he said.   It is not yet known whether the 300-member Malahat First Nation will continue to support the project following the election of a new chief and dismissal of three top economic development officials as part of a review initiated by new Chief Caroline Harry.   The agreement-in-principle was signed while former chief Michael Harry was in power and has raised the ire of some of the other four First Nations with land surrounding Saanich Inlet, who say they were not consulted.   Caroline Harry, who could not be reached before publication, said shortly after her election in November that she would reach out to Tsartlip, Tseycum, Pauquachin and Tsawout. Without Malahat support it is doubtful whether the project could proceed.

Steelhead has been talking to Malahat First Nation for 18 months, said Kuzemko, who does not believe there is any reason to think the relationship has changed with the election of a new chief and council.   “It’s going great actually. There are different concerns and a different environment with a new chief and council, but we will work with them,” he said.   Steelhead’s timeline calls for a final investment decision to be made in 2018 and, as with other companies looking at investing in LNG export plants in B.C., economics are likely to be a major factor.   Currently the LNG Asian spot price per million British thermal units is $5.72 and studies indicate that LNG prices are likely to remain low into the 2020s.   That means building LNG plants in B.C. makes no sense as the cost of fracking, transportation, capital costs, liquefying the gas and then shipping it to Asia would be about $12 per million British thermal units, Finn concluded after crunching the numbers.   However, Natural Gas Development Minister Rich Coleman said studies being used by the B.C government show that there will be a worldwide shortage of LNG within four or five years and, as it takes about four years to build an LNG plant, B.C. is well-positioned for developing a thriving LNG industry.   “If the demand is larger than the supply, the price will start to creep back to an economic level,” he said.   Kuzemko knows there are many hurdles before the project can start.   “B.C. is the most arduous location in the world to get approval,” he said.   “We know this project has to be community-based from the start. We are trying to do things in a different way.”

Image: Saanich Inlet by Lotus Johnson

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