Energizing the North – How Can we Drive Investment in Mining and Off Pipe Communities?

Energizing-the-north-with-natural-gas2In Canada’s Far North, powering operations presents challenges outside the mindset of most industries. From month-long nights to short shipping seasons, inflated transportation costs and lack of basic infrastructure like roads, operating in the North is difficult.

thermometer-icon-smDiesel has long been the mainstay fuel in the Arctic, but rising prices have prompted industry and communities to consider alternatives such as wind, and increasingly, liquefied natural gas (LNG) – natural gas that has been chilled (-162⁰C) into a liquid state – which can be transported by boat or truck to communities who do not have access to affordable natural gas.

“In these remote sites where there is no access to the grid, diesel will be the primary fuel to operate the facilities. And diesel is an expensive fuel, it’s expensive to ship, expensive to store. And a number of potential mines simply don’t proceed because the infrastructure costs, including the energy infrastructure costs, are prohibitive,” said Pierre Gratton, chief executive of the Mining Association of Canada.

Means of transport are limited in Canada’s north. Cargo, including diesel, propane or bunker fuel, is moved at great expense by barge and ship along the Saint Lawrence Seaway up to the Arctic via the Northwest Passage. Conversely, sites not located by tide water have about an eight-week window during the winter when the ground is frozen enough to support truck traffic on an ice road.

Means of transport can be limited in Canada’s far North.

Means of transport can be limited in Canada’s far North.

Each site has unique demands which lay the groundwork for its fuel of choice, from the least expensive but emissions-heavy bunker oil to wind turbines and natural gas for electricity generation. Power can represent up to 30 per cent of operating costs of a mine, therefore industry continuously seeks ways to trim that cost, either through energy efficiencies or through fuel switching when possible, the association said.

“Power can represent up to 30 per cent of operating costs of a mine, therefore industry continuously seeks ways to trim that cost.”

Operators of Red Lake mines in northern Ontario have been aware of the LNG alternative for two decades, but until about four years ago the logistics were too complex.

Old rail tracks leading to an abandoned mine shaft in Yukon Territory

Old rail tracks leading to an abandoned mine shaft in Yukon Territory

“We’re a small gold mine,” said Klaus Tietz, project manager of Gold Corp.’s Red Lake mine. “The economics didn’t pan out.”

Red Lake mine is located about two hours, or 180 kilometres north of TransCanada Corp.’s natural gas Mainline. An iron mine about 50 kilometres south of the mine had a trunk line to the natural gas pipeline, but there wasn’t enough of a population base in near-by villages or demand from the Gold Corp. mines to justify the expense of connecting with it, Tietz said.

Without access to the line, Gold Corp. had depended on propane to fuel its generators and underground ventilation systems. But that started changing by 2010.

“The price of propane had been going through the roof,” he said. “So basically we bit the bullet.”

The challenge is that northern communities’ distance from the nearest pipeline and sparse population, means the cost to construct and operate natural gas distribution infrastructure presents a significant economic hurdle.

The challenge is that northern communities’ distance from the nearest pipeline and sparse population, means the cost to construct and operate natural gas distribution infrastructure presents a significant economic hurdle.

Through a joint venture with Union Gas, the federal and provincial governments, the towns, and Gold Corp. supported a natural gas connector from the old iron mine trunk line to Red Lake.

The growth projected in the region for power consumption was a real tipping point, as well, going from 25 megawatt hours per day (MWh/d) to the 40-50 MWh/d range within several years, Tietz added.

Once the line was installed, the company used natural gas to heat air in the mine, reduce some of the electrical load, and fuel backup generators when needed – plus providing communities with natural gas.

“Connecting communities to natural gas supply is an important economic opportunity.”

“Connecting communities to natural gas supply is an important economic opportunity. It would help attract energy-intensive businesses and free up energy-related savings for residents, money that could be redeployed in the broader economy and contribute to local economic growth,” said Dave Simpson, vice president of infranchise sales and marketing and customer care at Union Gas.

In 2012, the distributor completed a $40 million project to bring natural gas service to the Red Lake area.  The jointly financed project was necessary, noted the utility.

“The challenge we know is that in northern Ontario communities, the distance from the nearest pipeline, pared with what’s usually a relatively sparse population, means the cost to construct and operate natural gas transmission and distribution infrastructure presents a significant economic hurdle,” said Andrea Stass, Union Gas media relations manager.

“It’s not an economically viable project as the cost to construct and service is quite often much more than any revenue that you might get from it.”

Union Gas operates the only LNG plant in Ontario, the Hagar Liquefaction plant, which will have 415,520 gigajoules of average annual activity beginning September 1, 2015.

Across the border, Quebec’s multi-billion dollar Plan du Nord economic development strategy includes promoting natural gas, with LNG as an option, in northern and Cote-Nord regions, ensuring supply and distribution by 2016.

Stornoway Diamond Corporation is taking part of the plan, developing its $1-billion Renard mine, the first diamond mine in Quebec, in the remote James Bay region, with support of a 29 per cent stake by the provincial government and natural gas utilities.

The company predicts it could save as much as 37 per cent in fuel cost by burning LNG at the mine, which is expected to start production in 2017.

“We are a remote site, powered by diesel, but now have access to the highway system and are able to truck natural gas to the site,” said Orin Baranowsky, director of investor relations at Stornoway Diamond Corporation.

Operators in Red Lake mine in Northern Ontario have been  aware of LNG for two decades.

Operators in Red Lake mine in Northern Ontario have been aware of LNG for two decades.

Provincial distributor Gas Metro plans on trucking in natural gas to the Cote-Nord region where large industrials burn oil, powering mines’ electrical generation north of Chibougamau, in the James Bay region, and bringing LNG to remote mining sites.

“The challenge is that you actually need to put the infrastructure in place before securing long-term contracts to ensure the certainty of supply to clients,” said Martin Imbleau, vice president of development and renewable energy for Gaz Metro. “After that, the markets will develop. That’s why we are jumpstarting the market and expanding the plant in Montreal East.”

The utility is expanding its 2.8 billion cubic foot (bcf) capacity natural gas liquefaction plant in Montreal by 6 bcf.

Word Cloud Emerging MarketsLike most northern communities in Canada, Whitehorse, Yukon, finds itself an isolated system, not connected to a major transmission grid outside its borders. Whitehorse is powered mainly by hydroelectric power system, with essential back-up operations fueled by costly diesel.

Yukon Energy Corporation’s aging diesel turbines in Whitehorse provide power for peak periods of use during the city’s frigid winter, and during periodic dry spells when water levels are low in the river. When the time came to replace the 40-plus year old generators, the utility looked into a range of cleaner burning power sources.

“When we explored other options it became clear to us that natural gas in the form of liquefied natural gas was an alternative.”

“When we explored other options it became clear to us that natural gas in the form of liquefied natural gas was an alternative,” said David Morrison, Yukon Energy’s chief executive officer.

“The challenge was securing a source of natural gas and the affordability of building a new gas-fired plant.”

Turns out the $36.5 million investment to build storage, gasification units, two 4.5megawatt natural gas-fired generators, and transportation would be paid out within three years. The short-term pain also translates to longer term savings of between $1 million – $2 million per year in fuel costs, Morrison said.

Yukon Energy estimated annual diesel costs of $4.51 million per gigawatt hour (GWh) versus LNG costs of $2.38 million per GWh in 2015. The difference increases dramatically by 2018 when fuel costs for diesel rise to $8.25 million compared to $3.85 million for LNG. The study, completed in March of this year, assumed natural gas prices of $4.50 per million British thermal unit (MMBtu), with an updated cost of $6.59/MMBtu to haul the fuel to Whitehorse.

“We felt that the argument for LNG has been compelling all along, on an economical and environmental basis,” Morrison said.

It quickly became apparent FortisBC was the most feasible opportunity. The Vancouver-based power generator already was supplying LNG to Inuvik, Northwest Territories, via trucks that moved along the Dempster Highway, and Yukon could piggy back on the transport, essentially paying for the 1,253 kilometre stretch between Whitehorse and Inuvik.

When it came to replace their 40-plus-year old generator Yukon Energy Corp. looked at a range of cleaner burning power sources.

When it came to replace their 40-plus-year old generator Yukon Energy Corp. looked at a range of cleaner burning power sources.

FortisBC  runs two LNG facilities, one supplying Vancouver Island at Ladysmith, B.C., and the Tilbury plant in Delta, B.C., where it is investing $400 million to expand the facility capacity to 35,000 gigajoules per day, plus increase storage to one petajoule.

The utility is helping replace diesel in northern communities like Watson Lake, B.C., as well as supplying pulp mills and helping mines adopt natural gas in their fleet. Doug Stout, FortisBC vice-president of energy solutions, said convincing companies to convert to natural gas is all about sitting down with its technical team, calculating total energy use, and bringing in information about conversion technology.

CGA-1_Route-SignIt takes about $300,000 to convert a mine haul truck, plus the company has to add in costs for new shop and fueling infrastructure. But mines are big fuel consumers so it’s a major cost item for mining corporation, Stout said.

lng-icon-smFor Fortis, “the trick is the demand: for one thing, (LNG) plants are fairly large-scale, not all $400 million, but tens of millions, and the consumption per community or per truck is pretty small incremental growth,” he said. “That’s the biggest challenge, trying to match capital investment with end use.”

Anecdotally, the costs of building natural gas storage is more expensive than building a diesel tank farm. But as technology evolves, the prices generally soften. Mining companies are more aware of what could be viable options to diesel, and doing their due diligence to be ready when prices fall and technology advances to consider implementation on their own sites to take advantage of cost benefits.

It takes about $300,000 to convert a mine haul truck to natural gas.

It takes about $300,000 to convert a mine haul truck to natural gas.

“Miners are keeping their eye on the ball to see when that synergy strikes. And you can see examples of that in more southern regions,” said Brendan Marshal, association director of economic affairs with the Mining Association of Canada.

He cautioned that while energy requirements were pretty consistent pricewise, logistics such as investment in infrastructure differ from project to project.

“So I don’t think there is a universal tipping point for all companies to move to natural gas. It’s something that fluctuates per project.”