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    [NGW Magazine] Canada's Eastern Promise


East Canada's reserves suffice to meet local gas demand, but the companies with the licences must first secure approval from the populations too.

by: Dale Lunan

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[NGW Magazine] Canada's Eastern Promise

This article is featured in NGW Magazine Volume 2, Issue 19

By Dale Lunan

East Canada's reserves would be more than enough to meet local gas demand and allow for exports, but the companies holding the licences will need to secure approval from the populations too – which means a lengthy process of consultation.

Three provinces in eastern Canada – Quebec, New Brunswick and Nova Scotia – share the potential to develop significant shale gas resources, and all three are at a tipping point when it comes to realising that potential.

New Brunswick and Nova Scotia have abundant shale gas resources, but the development of those resources is clouded by fracking bans.

Quebec has already undergone a moratorium on fracking, and has come out the other side with new energy and environmental legislation that sets the stage for more public consultation, perhaps leading to the development of its Utica shale gas. The Canadian Energy Research Institute (CERI) estimates that Quebec’s Utica shale resource has the second lowest supply cost in North America.

The largest potential is in the two Atlantic Canada provinces. In New Brunswick, the Frederick Brook Shale (FBS) in-place resource has been estimated at more than 67 trillion ft³, while the McCully field, which Corridor Resources and its partner, Potash Corporation of Saskatchewan, have been producing since 2003, has a modest 30.5bn ft³ remaining in a mix of tight gas sands and shale reservoirs – not a significant reserve, certainly, but still important in meeting demand in New Brunswick. If the New Brunswick fracking moratorium is eventually lifted, an additional 27bn ft³ of remaining reserves at McCully would be available.

In Nova Scotia, the Horton Bluff Shale (HBS) has an in-place resource estimated at between 17 trillion ft³ and 69 trillion ft³ and a risked recoverable potential of 3.4 trillion ft³.

But in both those provinces, development is blocked by bans that prevent hydraulic fracture stimulation, or fracking, that will likely remain in place for several years, until regulatory and political officials in both provinces get a handle on what, if any, environmental risks are posed by fracking.

The New Brunswick government, for example, has said the moratorium will remain in place until five elements are in place:

  • a ‘social licence’ to produce;
  • clear and credible information is available about the impacts of hydraulic fracturing on public health, the environment and water, allowing the government to develop a country-leading regulatory regime with sufficient enforcement capabilities;
  • a plan to mitigate the impacts on public infrastructure and to address issues such as waste water disposal;
  • a process to respect the duty of the provincial government to consult with First Nations; and
  • a mechanism to ensure that benefits are maximized for New Brunswickers, including the development of a proper royalty structure.

Map credit: Corridor Resources

Quebec, meanwhile, is in a somewhat different place in the development of its estimated 30 trillion ft³ of shale gas resource. A moratorium against fracking was imposed in 2011, but in the spring of 2016 a new provincial energy policy was unveiled that opened the door for the moratorium to be lifted. That summer, new hydrocarbon legislation was introduced in the form of Bill 106, while this past March, more modern environmental legislation was introduced.

Map credit: Corridor Resources

Now the real work begins

The real work, however, is only just beginning, according to the CEO of Questerre Energy, Michael Binnion. Questerre is the major Utica shale rights holder in Quebec.

The company must now earn “social acceptability” before it can proceed to develop the 5.8 trillion ft³ of Utica shale gas underlying its one million gross acres of Utica shale in the St Lawrence Lowlands region of the province, south of the St Lawrence River between Quebec City and Montreal.

Map credit: Questerre

The company and its partner, Repsol Oil & Gas Canada (formerly Talisman) drilled successful vertical test wells in 2008 and 2009, and in 2010 began a pilot horizontal drilling program to assess the commercial viability of the Utica shale in Quebec. That autumn, however, the pilot was suspended while the province launched an environmental assessment of shale gas development that would ultimately lead to the moratorium on fracking in 2011.

What followed were two reviews by Quebec’s environmental regulator, the Bureau d’audiences publiques sur l’environnement (BAPE), and strategic environmental assessments of both conventional and unconventional oil and gas resources in the province.

All of that took five years, and culminated in the publishing of a Green Book that would guide Quebec’s environmental future, and a new provincial energy policy that would guide its oil and gas future.

“The big breakthrough was over a year ago with the publishing of the new energy policy, which stated the obvious, which was that if you’re concerned about hydrocarbons you are better off, socially, environmentally and economically, to use local ones than foreign ones,” Binnion told NGW. “That was a real breakthrough because in 2011 the solution was bans and moratoriums; five or six years later we got a policy. I think that policy victory was probably one of the biggest public policy victories for oil and gas in the last 10 years.”

New regulations

On September 20, the Quebec government released draft regulations that will govern future oil and gas development in the province, and while Questerre Energy and other licence holders in Quebec must still review them and provide feedback, Binnion is encouraged by what he has seen.

"Our preliminary review suggests these regulations reflect some of the highest standards in North America for oil and gas activity,” he said in a news release, adding that they incorporate the results of over 100 studies conducted in Quebec and best practices in other jurisdictions.

But again, he cautioned, the regulations are only another step along the way to development.

“The regulations by themselves are absolutely essential and necessary, but not in themselves sufficient to go forward,” he told NGW. “To go forward we need to move forward, together with people in the local communities, and to have general acceptance that what we are doing is good for the environment, for the community, and for the economy.”

To gain social acceptability – what others may call ‘social licence’ – Questerre will have to tread a carefully thought-out path of building relationships one-on-one throughout the St Lawrence Lowlands, Binnion said. That path goes far beyond holding a series of town hall meetings, the traditionally accepted methodology for informing the public about oil and gas developments.

“There will be town halls, and they will be important, because that’s the part that the media and the public will see, but 90% of the work on the campaign will be about building relationships, one by one, group by group, with people so that they come to those town halls saying: “Yes, I think these are good people and I am going to listen to what they have to say,’” Binnion said. “The problem is that we go to a town hall and we think we are going to convince people at a town hall. That will not happen unless they are already convinced.

“That 90% of the social acceptability campaign will be to convince those hyper-engaged opinion leaders who exist in every society and every community that this is good for them so that when you come to the town hall you are now explaining to a group of people who are convinced.”

The key, he said, is that there shouldn’t be any surprises when it comes time to finally file a development application, that the public shouldn’t be presented with a fait accompli.

“That’s the old model and I think we’ve seen from our first crack in 2010 that it doesn’t work,” he said. “We’ve seen from Energy East and Northern Gateway and the other pipeline applications that it just doesn’t work any more.”

Lessons from Quebec

The same sort of “listen-learn-lead” approach could work well in Nova Scotia and New Brunswick, where a promising unconventional gas industry has been stifled by fracking bans that have been in place since 2014 and 2015 respectively.

With production from Nova Scotia’s two offshore developments – ExxonMobil’s Sable Offshore Energy Project (SOEP) and Encana’s Deep Panuke field – dwindling, further exploitation of New Brunswick’s only producing onshore field stymied by the fracking bans, and gas demand expected to increase steadily over the next 20 years, both provinces are, “without a doubt, on the cusp of fundamental change,” CERI said in a recent study examining the economic potential of onshore oil and gas in New Brunswick and Nova Scotia.

The study presented three possible scenarios for onshore oil and gas in the provinces: maintenance of the status quo, with the fracking bans remaining in place indefinitely; lifting of the bans, but with future onshore development limited to meet only local demand; or full-on development, with production maximised to meet not only local demand but also to tap into pipeline and LNG export markets.

To meet local gas demand in the first scenario, both provinces will have to dramatically increase imports either through a reversal of the existing Maritimes & Northeast Pipeline (M&NP), a 550mn ft3/day line that delivers offshore gas to the US, or through the Canaport LNG terminal in New Brunswick.

Additional LNG facilities are also contemplated in the region: Bear Head LNG has approvals in place for an 8mn metric tons/year (mt/year) terminal at Point Tupper, in Cape Breton, while Pieridae Energy is interested in building a 10mn mt/year terminal at Goldboro, Nova Scotia, near where SOEP and Deep Panuke volumes come ashore. Both projects are drawing increased interest from western Canadian producers as planned west coast terminals fall by the wayside.

In the second scenario, both the FBS in New Brunswick and the HBS in Nova Scotia would be developed with fracked wells, but production would be constrained at 111.9mn ft³/day in New Brunswick and 152.4mn ft³/day in Nova Scotia. In the third scenario, production from New Brunswick and Nova Scotia are each assumed to be constrained at 550mn ft³/day, the existing capacity of M&NP.

Reaping the economic benefits

The economic benefits of pursuing either of the latter scenarios, CERI said, are significant: in the second scenario, more than 33,000 man-years of employment would be created in Nova Scotia and New Brunswick over the 20-year period between 2017 and 2037, while the GDP impact of development would approach $13bn in the two provinces and exceed $14bn across Canada; the third scenario would see nearly 111,000 man-years of employment and GDP increase by some $36.6bn in the two provinces and by $42bn nation-wide. Neither of those two scenarios, it should be noted, include the impact of either the Bear Head or Pieridae LNG proposals.

Before either scenario can be contemplated, however, both provinces will need to be convinced that the economic benefits of fracking outweigh any potential environmental impacts. That means, the CERI study said, that additional data collection and monitoring of environmental and health impacts are required, along with a “science-based, adaptive and outcomes-based regulatory approach” to unconventional oil and gas development in both provinces.

And, it noted, just that sort of process has evolved in Quebec over the last six or seven years. “It is interesting to note that Quebec presents a unique example of a jurisdiction that has employed a listening-learning-leading approach, transitioning from a moratorium on hydraulic fracking to the introduction of Bill No. 106, the introduction of a new hydrocarbons law in Quebec,” CERI said.

That approach began with listening, through a long series of environmental hearings. This was followed by learning, through a variety of environmental assessments and knowledge acquisition plans, and finally culminating in leading, with the introduction of “the capstone, Bill 106.”

As offshore production falls and local demand for natural gas rises, both jurisdictions will need to weigh the options, moving forward, for how and where local demand for natural gas will be met, CERI concluded. “To what extent [development is allowed], to either satisfy their local needs or to become exporters, or perhaps just to import from the US northeast or abroad, the decision has many variables and cannot be taken lightly.” 

Dale Lunan