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This piece also appears on Policy Note, by the Canadian Centre for Policy Alternatives.
In the past year, an energy dispute for the ages has played out in Canada, culminating in the federal government announcing it will buy an aging oil pipeline for $4.5 billion and then twin it with a new high-capacity pipeline that would move massive amounts of diluted bitumen from Alberta to tidewater in British Columbia.
Prime Minister Justin Trudeau’s vow that “we’re going to get that pipeline built” has been music to the ears of Alberta Premier Rachel Notley, but has struck a discordant note with B.C. Premier John Horgan, who continues to oppose the project on the grounds that a tanker spill would cause irreparable harm to Canada’s west coast and to B.C.’s coastal economy.
But as federal and provincial leaders continue to squabble over the proposed westward movement of Alberta’s “land-locked” bitumen via the Trans Mountain pipeline route, there’s a giant elephant in the room that nobody’s talking about.
What about the exploding trade in fossil fuels moving east from British Columbia into Alberta and points beyond?
There is a deep irony at play in the high drama we are witnessing: heavy oil production in Canada’s petro province of Alberta is powered, in part, by a glut of cheap natural gas in North America, which gas producers in B.C. have helped to create.
B.C. is also helping to prop up Alberta’s oil industry by shipping it lots of extremely valuable “gas liquids” — by-products of natural gas which are essential to dilute heavy oil or bitumen so that it can move more readily through pipelines.
But you wouldn’t know that by looking at most media accounts.
Much of that out-of-sight, out-of-mind energy flow is also, paradoxically, heavily subsidized by the B.C. government. Once again, it barely rates a mention in the mainstream press.
In the last 10 years, B.C. has effectively become a preferred supplier to its neighbour, the oilsands powerhouse just to the east: a reality with grim implications for the environment and economy in Canada’s two westernmost provinces, to say nothing of our global climate.
So, to stimulate discussion about where we are heading with the west-to-east energy trade that is actually happening (as opposed to the dramatically expanded east-to-west trade that might one day happen), consider the following.
Alberta’s oilsands industry is the top consumer of natural gas in Canada, accounting for one quarter of all the natural gas used in the country. Much of that gas is combusted to generate steam that is pumped below ground, to “liberate” the thick oil. As oilsands operations expand, more natural gas must be consumed. It is to the industry’s benefit to see lots and lots of natural gas produced from whatever quarter, and of even greater benefit to the industry if increased gas production results in a glut of marketable gas, which keeps prices low.
In the ten years ending in 2017, Alberta-bound shipments of natural gas from northeast B.C. increased by more than 230 per cent. In fact, virtually all of the sizeable increase in B.C.’s overall gas production went to its neighbour to the east. Some of that gas was used in Alberta; the majority then moved farther east to markets in central Canada and the United States.
Contrary to B.C. Energy Minister Michelle Mungall’s frankly embarrassing assertions that continued natural gas drilling and fracking is necessary so that British Columbians can bask in the warmth of their gas fireplaces, and so those lucky enough to afford it can cook salmon on their gas barbecues, the overwhelming majority of natural gas drilled and fracked from the ground in northeast B.C. goes to others. It is not used in this province.
If the pilot lights ever wink out in the fireplaces in British Columbians’ homes, it won’t be because of B.C.’s own natural gas consumption, but rather the province’s subsidized gas production (the biggest subsidy of which is the extremely generous breaks on gas royalty payments that the B.C. government grants natural gas producers).
Those subsidies are a powerful inducement to the industry, particularly in the Montney Basin, the southernmost of the two big natural plays in the province, where there’s plenty of natural gas. But there is also plenty of something else, which is the only thing that is really driving industry profits these days.
Within the Montney Basin, which includes operating areas near the communities of Fort St. John, Dawson Creek and Chetwynd, the favoured drilling sites are those containing large amounts of naturally occurring “wet” gas liquids, as opposed to the “dry” conventional natural gas or methane. The most important of those liquids are pentane and condensate, which are used to dilute bitumen or heavy oil, thus allowing it to flow through pipelines. Hence the name “dilbit.”
Condensate is also sometimes called natural gasoline. In addition to flowing to the surface at drilled and fracked gas wells, it is also separated from the dry gas at gas processing plants.
The big user of all the wet gas that B.C. produces? You guessed it. Alberta’s heavy oil industry. Last year, according to B.C.’s Ministry of Energy, Mines and Petroleum Resources, B.C. produced a record 19.7 million barrels of condensate, slightly more than one fifth of Alberta’s production. Without B.C., Alberta’s oilsands producers would have had to ramp up condensate shipments from the U.S. to make up the difference.
So lucrative is the trade in those liquids that Encana Corporation, one of the biggest players in the Montney Basin, says that its “continued margin expansion” in the region will be “driven” by the increasing volumes of gas liquids that it produces.
According to a corporate presentation prepared by Encana in July, the company aims to produce up to 65,000 barrels per day of gas liquids at its Montney Basin operations by the fourth quarter of 2018. That would then mean that Encana alone produces nearly 24 million barrels per year of Alberta-bound liquids. Other major gas liquids producers that also have substantial holdings in liquids-rich zones in the Montney Basin include Tourmaline Oil Corp. and ARC Resources Ltd.
But here’s where the irony of the B.C. government’s objection to the Trans Mountain project grows even thicker. Like all of that Alberta-bound natural gas, the lucrative gas liquids heading to Alberta are used to prop up the petro province’s heavy oil industry. They are essential in allowing thick, unrefined Alberta oil and bitumen to move through pipelines. Paradoxically, B.C.’s eastern-bound gas liquids could one day facilitate the westward movement of diluted bitumen through that new pipeline that Ottawa and Alberta are so intent on building.
For years, the B.C. government has encouraged fossil fuel companies to produce more natural gas and liquids by offering generous discounts on the royalties that companies pay to British Columbians on each unit of gas produced.
Those discounts are primarily in the form of “deep well credits.” Successive provincial governments have allowed companies that drill deep natural gas wells to claim a portion of the drilling costs as credits, which are then reimbursed by the province in the form of lower royalty payments.
More recently, those credits have also been extended to companies that drill horizontal wells, despite the fact that both deep wells and horizontal wells are now standard industry practice.
The end result is billions fewer dollars flowing into provincial coffers and from there into public programs like health and education. In the last 10 years, according to figures supplied by Cathy Mou, markets analysis manager for B.C.’s Energy Ministry, the difference between the gross royalty charges to companies drilling for natural gas and gas liquids in northeast B.C. versus the net royalty payments they actually made was close to a combined $5 billion. A significant factor behind those reduced payments were the above-mentioned credits.
Just how much individual companies have benefitted from those subsidies, however, is something that the B.C. government keeps secret. In March, the B.C. government formalized this secrecy by appending a new “confidentiality” provision to an amended Petroleum and Natural Gas Act. The amended Act, Ministry of Finance officials now claim, expressly forbids them from disclosing such information.
In short, British Columbians are no longer allowed to know what, precisely, individual fossil fuel companies operating in the province pay in royalties and receive in credits.
One day after the Canadian Centre for Policy Alternatives first reported on the confidentiality provision and the ministry’s refusal to release company-specific royalty payment information, Green Party Leader Andrew Weaver asked Energy Minister Mungall about the matter during Estimates Debate.
“My question to the Minister is: is she comfortable with this, given the stark contrast to the forest industry, in which the volume of timber harvested by specific companies is publicly available information? What is the justification for this level of secrecy?” Weaver asked.
“My understanding,” Mungall replied, “is that this is very similar, actually, with mining in that the Ministry of Finance has determined that a best practice is to treat royalties, in terms of their privacy, the same way as you would treat individual income tax. We want to protect that privacy information for industry in the same way that we would protect privacy information for individuals.”
Mungall scrupulously avoided responding to Weaver’s questions regarding the forest industry, which was a notable omission. Notable because any member of the public with a little know-how can use a database maintained by the provincial government and free to users to learn precisely how much timber is logged by individual companies in B.C. and what those companies pay to the province in return. In other words, members of the public are entitled to know what logging companies pay in stumpage fees (essentially a royalty payment for a publicly owned resource) but they are not entitled to know what fossil fuel companies pay in natural gas royalties.
B.C.’s generous trade in natural gas and wet gases with Alberta carries with it enormous ecological costs, almost all of which are borne by Indigenous and non-Indigenous communities located in the northeast region.
This includes stunning and repeated violations of provincial laws, for example fossil companies building dozens of unlicensed dams to trap water for use in their increasingly intense fracking operations — dams built under the watch of the fossil fuel industry’s own dedicated regulator — the B.C. Oil and Gas Commission (OGC).
It also includes evidence of groundwater contamination at potentially hundreds of gas wells in the remote northeast of the province, evidence that the OGC withheld from the public for four years and apparently never bothered to share with successive provincial energy ministers.
It also includes evidence of natural gas companies repeatedly breaking rules to protect threatened wildlife species, with the OGC once again withholding that information from the public.
It also includes evidence of mounting liabilities at abandoned well sites where insufficient industry funds have been posted to cover environmental reclamation costs, and where the provincial government may now be on the hook to cover clean-up costs.
And it also includes disturbing evidence of massive amounts of methane leaking into the atmosphere at numerous gas well sites and wreaking climatic havoc. Given this, it is entirely conceivable that if the day ever came when a major liquefied natural gas (LNG) facility — or more accurately, a liquefied fracked gas plant — was built in B.C., the greenhouse gas emissions associated with that gas would put it on par with coal.
These are the consequences of B.C. adding to the temporary glut of natural gas on the North American market and producing more and more gas liquids for use in Alberta’s oilsands industry. More consequences will almost certainly become apparent as increased gas drilling and fracking occurs in northeast B.C., and the fossil fuels produced head east.
So let’s take just a little closer look at what it means to be a petro state lackey.
In 2008, fossil fuel companies operating in northeast B.C. produced 27.4 billion cubic metres of marketable gas. A decade later that production, fuelled largely by advances in shale gas drilling and fracking, stood at nearly 48 billion cubic metres.
Even more pronounced has been the explosive cross-border flow of gas liquids to Alberta. In 2007, fossil fuel companies produced 2.97 million barrels of condensate. Today, that output is 6.6 times higher and closing in on 20 million barrels.
That production, however, is poised to skyrocket. In 2016, Encana drilled 17 wells in northeast B.C. One year later, the number of wells drilled hit 107.
“Natural gas production from the Montney play straddling Alberta and B.C. hit a record high in 2017, but the best economics in the fairway come from higher value condensate, and that’s what’s going to drive more ‘focused activity levels’ this year,” the industry watchdog JWN Energy Group reported in January of this year in an article that featured a photograph of a giant drilling rig at an Encana operation in the Montney.
The same JWN report noted that companies operating in the Montney were likely to benefit from high condensate prices in the coming year. The high prices, combined with the Montney Basin’s proximity to Alberta’s oilsands producers meant that the “operating netbacks,” or net profits, on each barrel of condensate sold would be in the range of $53.
At least part of the reason for those healthy profits are the low royalties that companies like Encana pay to the B.C. government as they draw gas and gas liquids from the ground in their fracking operations.
The big winners in that are the companies that produce and sell the condensate and pentane to the oilsands industry, particularly those companies that drill and frack in liquids-rich zones close to where the oilsands industry operates. Because the Montney Basin is relatively close to where the oilsands industry operates, the costs to ship liquids from B.C. to Alberta are far lower than the costs of moving the same product into Alberta from the United States. Lower shipping costs thus translate into increased profits for liquids producers in Alberta and B.C. alike.
As more gas wells are drilled in northeast B.C. to coax more valuable liquids from the ground, something else is happening. More and more natural gas is being produced as well. You can’t have one without the other.
A glut of available natural gas now and in the foreseeable future is music to the ears of oilsands producers, says Bill Gwozd, a veteran, Alberta-based natural gas analyst and consultant.
“If you’re a big, big oilsands producer and you’re buying gas for your operation, cheap gas is good,” Gwozd said in March when interviewed for an article in the Calgary Herald.
With drilling activity increasingly targeting liquids-rich formations, Gwozd said it is reasonable to expect that even more natural gas will be produced, again to the advantage of the oilsands industry.
But the expanding pool of natural gas also means that unease is growing among companies that produce mostly natural gas and that see depressed prices for their product for a long time to come. Like their counterparts in the oilsands industry who are anxious to see a pipeline built to carry diluted bitumen from Alberta to tidewater in Burnaby, a growing number of gas producers are anxious to get their “land-locked” product to the West Coast as well. Translation? Another east-to-west pipeline, but one carrying natural gas from the Montney to tidewater in Kitimat.
Once at tidewater, the gas would then be super-cooled to liquid form at a massive new LNG plant and export terminal, whose lead proponent is Shell.
Gwozd is at the forefront of efforts, now, to create a new industry association dedicated to increasing the financial returns to companies that produce natural gas and gas liquids in B.C. and Alberta.
The Calgary Herald article noted that Gwozd, along with Calgary-based consulting firm Gas Processing Management Inc., was starting a new industry association called the Centre for Gas and Liquids Monetization (CGLM).
Among the big names considering joining the centre is Chevron. Chevron could become a partner in the LNG Canada project that Shell would lead. Progress Energy, a subsidiary of Malaysian state-owned Petronas, is also the single-largest subsurface rights holder of natural gas assets in northeast B.C. It, too, would be a partner should the LNG Canada project proceed.
When it comes to pipelines on Canada’s West Coast, it is clear that Premier Horgan has no problem saying no to some and yes to others.
As far as LNG is concerned, the Premier not only supports a new pipeline, processing facility and port, but is prepared to offer generous tax breaks to make it happen. In announcing the incentive package in March, Horgan said the amount of gas industry revenues that the province was prepared to forego, should Shell and its partners proceed with the project, would be $6 billion over a 40-year period.
All of which means that one day B.C. might have a whole bunch of masters.
One master just to the east who continues to benefit from a glut of cheap natural gas on the market and who will take all the highly sought-after gas liquids that B.C. can give.
One or more masters on the other side of the Pacific Ocean that will be only too happy to take all the LNG the province can send them.
And, if Justin Trudeau and Rachel Notley have their way, another master or two at points yet to be determined, if and when diluted bitumen one day moves through a new pipeline to Burnaby — bitumen enabled in part by a whole bunch of natural gas liquids produced in B.C.
Ben Parfitt is a resource policy analyst at the Canadian Centre for Policy Alternatives – B.C. Office.
This piece was published as part of the Corporate Mapping Project (CMP). The CMP is a six-year research and public engagement initiative jointly led by the University of Victoria, the Canadian Centre for Policy Alternatives’ B.C. and Saskatchewan Offices, and the Alberta-based Parkland Institute. This research was supported by the Social Science and Humanities Research Council of Canada (SSHRC).
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