Total SA snubs ‘expensive’ U.S. shale with North Sea-focused deal

When Total SA warned last month it was ready for acquisitions, U.S. shale assets weren’t at the top of its shopping list.

On Monday, the French energy giant agreed to buy the oil and gas unit of A.P. Moller-Maersk A/S, its biggest purchase since 1999. The $7.45 billion deal, including debt, reinforces Total’s footprint in conventional oil and gas assets in Europe and Africa. U.S. shale — whose development over the past decade has upended the balance in the oil market — won’t be part of the portfolio.

Chief Executive Officer Patrick Pouyanne said shale assets were “quite expensive” and that Total wasn’t the best company to develop them. The deal puts a value of about $50 to $55 a barrel on Maersk, while U.S. shale is closer to $80, he said. Benchmark Brent crude traded at $51.67 a barrel as of 4:03 p.m. London time.

U.S. shale tends to have “higher asset prices,” Brendan Warn, head of international oil and gas equity research at BMO Capital Markets, said by phone. “It’s not Total’s core competency. They’ve tended to be contrarian almost and focus on offshore, conventional” and longer-cycle projects.

The transaction will add about 1 billion barrels of oil equivalent to Total’s reserves, with more than 80 percent of those in the North Sea, spanning Norway, Denmark and the U.K.

Consolidation Deal

“The deal is really about consolidation in the North Sea,” Valentina Kretzschmar, a corporate director at energy consultancy Wood Mackenzie Ltd., said by phone. 

Total is present in the U.K. North Sea through Laggan-Tormore, which started producing last year, as well as in the Elgin-Franklin project.

With the Maersk deal, the major will add an operating stake in Culzean, another U.K. North Sea project that’s expected to meet 5 percent of total U.K. gas demand. Total will also get an 8.44 percent stake in the giant Johan Sverdrup oil field off Norway, which is scheduled to start pumping in late 2019.

“They are buying the highest quality asset offshore-wise in the world which is Johan Sverdrup,” Havar Blakset, partner at consultancy Rystad Energy AS, said by phone. “This deal makes sense.”

The acquisition will yield cost synergies, particularly in the North Sea, of more than $400 million a year, Total said.

The assets acquired will add 160,000 barrels of oil equivalent to Total’s production next year, climbing to 200,000 barrels early next decade. The company’s oil and gas production will immediately increase by 6 percent, according to Wood Mackenzie.

Shale Gap

The decision to buy an explorer and producer whose assets are more than two-thirds oil is “surprising” since Total expects gas to make up the biggest share of its portfolio by 2035, Kretzschmar said. 

While Total is exposed to U.S. shale gas via its Barnett assets in North Texas and the Utica assets in Ohio it bought for $2.3 billion in 2012, it has the smallest presence in the shale patch among European majors, she said. 

Price has so far been a deterrent to further expansion.

“You have to put $80 dollar-a-barrel assumption in the model and I’m not ready at all to acquire assets at $80 dollar per barrel,” Pouyanne told analysts on a conference call Monday.”It will make some of the owners of the resources very happy; I’m not sure it would make shareholders very happy.”

Still, that won’t necessarily stop the French company from continuing to hunt for assets.

“U.S. shale is a gap in Total’s portfolio and we think that Total will still be looking for opportunities,” Kretzschmar said. “The price is going to be the key determinant.”

–With assistance from Geraldine Amiel and Javier Blas

Historic eclipse will test U.S. power grids with 12,000 megawatts expected to fall offline

On Monday, the first total eclipse of its kind in 99 years will plunge broad swaths of the U.S. into darkness, sending solar supplies sliding and testing the resilience of the power grid for the first time since the rapid rise of renewable energy.

Grid operators, utilities and electricity generators are bracing for more than 12,000 megawatts of solar power to start falling offline as the moon blocks out the sun across a 70-mile-wide (113-kilometres) corridor stretching from Oregon to South Carolina.

This is the first major test of the power grid since America started bringing large amounts of intermittent solar and wind resources onto the system. It comes just as the grid is undergoing an unprecedented transformation whereby flexible resources such as battery storage will complement growing supplies of solar and wind. Solar installations have grown ninefold since 2012 and renewable sources are forecast to supply just as much of America’s electricity demand as natural gas by 2040.

The U.S. power grid “hasn’t seen this sort of natural phenomenon since solar became a thing,” Nicholas Steckler, an analyst at Bloomberg New Energy Finance, said. “With so many renewables coming online, especially in the last five to ten years, there is more impact from an eclipse.”

The eclipse is expected to reach the U.S. at 9:05 a.m. local time at Lincoln Beach, Oregon, and last for about four hours. Back-up, natural-gas plants and hydroelectric dams are at the ready to fill solar’s void along with new technologies to control demand.

Regional grid operators from California to Pennsylvania plan to provide real-time updates on how their networks are handling fluctuating power flows as millions of Americans head outside to gaze at the sky.

The celestial event provides an opportunity to test plants, software and markets refined in recent years in anticipation of the day when renewable energy becomes the dominant source of power. Bloomberg New Energy Finance has projected that renewables will supply more than half of the world’s electricity in 2040.

California, home to more solar power than any other state, will tap into its network of hydropower generators and gas plants that can ramp up quickly to fill a 6,000-megawatt gap in solar energy. The state also embarked upon a public relations campaign to convince residents to conserve energy to minimize greenhouse-gas emissions while solar plants are down.

In North Carolina, part of which will see total darkness during the eclipse, Duke Energy Corp. expects about 2,000 megawatts, or 80 per cent, of utility-scale solar farms to go offline. The utility will treat it like a “gradual sunset,” said Tammie McGee, a company spokeswoman, estimating that as many as 1,200 megawatts of gas generation will be called upon to pick up the slack.

Wholesale electricity prices may rally on solar’s sudden slide. The eclipse will start curbing power supplies a little after 9 a.m. on the West Coast, just when the work week is starting and demand is taking off. According to energy data provider Genscape Inc., the event may extend the typical period of high power prices in California by about two hours.

Prices will probably retreat as soon as the moon starts moving past the sun and solar farms return, Genscape said. And the market impact in Texas, the Midwest and the East Coast will be limited because the region’s home to smaller concentrations of solar.

Bloomberg News

Sempra Energy beats out Berkshire with US$9.45 billion offer for Oncor

U.S. utility owner Sempra Energy has agreed to buy control of Texas power distributor Oncor Electric Delivery Co. for US$9.45 billion, topping a bid by Warren Buffett’s Berkshire Hathaway Inc. just last month.

Sempra’s deal for Energy Future Holdings Corp., which owns 80 per cent of Oncor, is valued at about US$18.8 billion including debt, the San Diego-based company said in a statement dated Aug. 20. Sempra plans to fund the purchase through a combination of its own debt and equity, as well as third-party equity and US$3 billion of borrowings by the reorganized company, it said. 

Just six weeks ago, Berkshire struck a deal to buy Oncor for US$9 billion. Shortly after, billionaire investor Paul Singer’s Elliott Management Corp. fired back, saying it was working to pull together a rival bid that may total US$9.3 billion.

Elliott voiced its support of the Sempra deal Monday, saying in an emailed statement it provides “substantially greater recoveries” to all Energy Future creditors than Berkshire’s offer.

Sempra is the latest to join a line of suitors who’ve sought to take over Oncor since its parent Energy Future declared bankruptcy in 2014. The deal may put an end to the escalating battle between Buffett and Singer and would be Sempra’s largest acquisition since it was formed in 1998, based on data compiled by Bloomberg, expanding its U.S. utility territory beyond California.

Sempra received financing commitments for the deal from RBC Capital Markets and Morgan Stanley, it said in its statement. It expects the transaction to be completed in the first half of next year. Lazard and Morgan Stanley advised Sempra, with White & Case LLP acting as legal advisers, it said.

The deal is key to ending Energy Future’s bankruptcy, which has now spent more than three years working to restructuring almost US$50 billion of debt. A judge was scheduled to consider Berkshire’s offer during a U.S. bankruptcy court hearing in Wilmington, Delaware, on Monday.

The merger agreement with Berkshire included a termination fee of US$270 million, subject to certain conditions and court approval, according to a regulatory filing. Berkshire has said it’ll walk away from the deal if a judge doesn’t approve the plan on Monday.

Failed offers

Others have tried and failed to take over the Texas utility, which serves almost 10 million customers and operates more than 106,000 miles (170,590 kilometres) of distribution lines.

Earlier this year, Texas utility regulators quashed an offer from NextEra Energy Inc., valued at US$18.4 billion including debt, after the utility giant refused to establish ring-fencing measures to protect Oncor’s credit. A group led by Hunt Consolidated dropped a bid last year after the state imposed conditions it found too onerous.

“It’s not just a question of what you’re offering — it’s a question of whether or not it’s going to make Texas regulators feel comfortable enough to allow the deal,” Paul Patterson, a utilities analyst at Glenrock Associates LLC in New York, said by phone. “And we’ve already seen two fail in this situation.”

Sempra said in its statement announcing the deal that it “will maintain the existing independence of Oncor’s board of directors, which has protected Oncor and its customers during the ongoing Energy Future bankruptcy.”

Energy future

Energy Future was formed a decade ago by KKR & Co., TPG Capital and Goldman Sachs Capital Partners as part of the biggest leveraged buyout in history. It sought protection from creditors after natural gas plummeted, dragging down wholesale prices for the power the company was generating.

Sempra runs power and gas utilities in Southern California, Chile and Peru that altogether serve more than 32 million consumers, according to the company’s website. It also owns and operates almost 2,400 megawatts of renewable energy capacity with partners; the Mexico pipeline developer IEnova; and a liquefied natural gas export terminal project in Louisiana with partners.

Last year, Sempra pulled out of talks to buy a stake in a planned US$6.5 billion natural gas pipeline project in Peru after the country’s government refused to a remove a condition but has since said it may re-bid for the project. In December, the company’s IEnova unit bought wind power assets in Mexico for about US$900 million, including debt.

Elliott recently bought debt in Oncor’s parent in its latest effort to block Berkshire’s bid, people familiar with that matter said Aug. 16. Buying the notes means Elliott and and Sunrise Partners, which also opposes Berkshire’s offer valued at US$18.2 billion with debt, own the majority of every class of impaired credit in the holding company, one of the people said. That might allow Elliott to block the Berkshire deal as a so-called dissenting impaired class of creditor under bankruptcy law.

Bloomberg News

Scorching heat, rolling blackouts: The west is changing how it does summer

This June, we received a letter from a reader asking why it seemed like there are fewer summer blackouts, especially in the western US, than there used to be.

This resonated with me. When I was a kid growing up in Southern California, summer always seemed to bring with it a couple of electrical blackouts. By 2001, the term “rolling blackouts” was a household phrase. The morning news would warn of a heatwave. My sister and I would head out to a friend’s house or some local summer camp, and when we returned home from pool-bleached adventures the power would go dead. Sometimes the blackouts lasted just a few minutes. But occasionally, hours passed and my parents would get cranky, sweating miserably with no way to know when we could get the air conditioner back on.

For me, it’s a trivial memory to think back on—my 20-years-younger parents wondering if they should wait for power to cook dinner or just have everyone fend for themselves in the slowly-warming fridge. We were lucky. We were a young family with bodies that were able to withstand a couple hours of heat. But blackouts aren’t just a minor inconvenience for some people. Surely, there were less fortunate people who suffered hyperthermia during these heatwaves. The very old and the very young are particularly susceptible, but blackouts are problems for businesses, too. Back then, the fledgling world of the dot-com boom was just figuring out how to deal with overheating servers and dropped conference calls.

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As Dakota Access comes online, America’s most pipeline-constrained shale play sees new life

Ian Dundas expects to see far fewer oil trains rumbling across the sprawling farmlands of North Dakota in coming years.

Dundas is the chief executive of Calgary-based Enerplus Corp., one of the first companies to enter the Bakken, an oilfield spanning southern Saskatchewan, North Dakota and Montana. In the absence of available pipeline capacity, companies operating in the region had for years moved oil on an existing rail network in Canada and the United States. As production boomed, producers began investing more in oil-by-rail terminals, paying a premium to get their product to market.

But the completion of the highly contentious Dakota Access pipeline in June, a major oil conduit carrying some 570,000 barrels per day of crude from North Dakota to Illinois, has upended the region’s dependence on rail.

The pipeline has dramatically reduced shipping costs for Bakken companies, bringing overall costs in line with other U.S. shale producers, like those in the highly prolific Permian Basin in Texas and New Mexico.  

“It’s going to be a pretty powerful advantage that we haven’t had for the past six or seven years,” Dundas said in an interview Thursday.

Production in the Bakken began to rocket upward around 2009, growing from roughly 200,000 barrels per day to more than one million bpd in less than five years.The rapid growth did not come alongside an equally fast expansion of pipelines, however, and the pipeline system in the region quickly became congested. By 2014, Bakken producers were shipping around 500,000 barrels per day of crude by rail car, nearly half of the 1.2 million bpd total production.  

Before Dakota Access, about 25 per cent of the oil shipped out of the state travelled by rail. Now that figure is closer to seven per cent, according to recent data. 

The higher availability of pipeline capacity has translated into much lower shipping costs for producers, giving companies more value for every barrel of oil. 

In early 2014, for example, Enerplus was receiving a US$13 per-barrel discount for its oil compared to West Texas Intermediate, a benchmark price for U.S. crude traded in Cushing, Okla. Most of this was tied to higher shipping costs (moving crude by rail costs around US$10-14 per barrel, compared with about US$5-6 on Dakota Access). 

By last year, that total discount had shrunk to US$7, and is expected to fall as low as US$3.50 in the second half of 2017, Dundas said.

“These are pretty dramatic moves when you talk about the lower margins that everyone is struggling with in a $50 oil world,” Dundas said.

The Dakota Access pipeline, owned by a consortium of companies led by Dallas-based Energy Transfer Partners, was loudly opposed by environmental groups and First Nations groups living along the proposed route. 

The Sioux First Nation in Standing Rock, a reservation that straddles the North and South Dakota borders, protested the pipeline in a standoff that lasted for months. People were eventually forcibly removed from a site they had used as a staging ground for the protest.

Although the pipeline has been in service for months, the same opposition groups are now trying to get the pipeline shut down due to allegations the consortium had removed too many trees and improperly handled some soil during construction.

In June, a federal judge seemed to question the validity of Dakota Access’s approval based on the alleged infractions, saying the consortium’s study didn’t fully address environmental risks caused by potential spills. U.S. Army Corps of Engineers, who carried out the initial environmental review, has been asked to compile a new report.

Observers don’t expect the project will be shut down due to the decision. 

“I think that would be very, very unlikely,” said Patrick O’Rourke, an analyst with AltaCorp Capital in Calgary. “I can’t think of a situation has come online, started flowing, and then had to cease operations.”

On Thursday, the North Dakota Public Service Commission delayed hearings on whether the company violated state rules.

Bakken producers are nonetheless relieved to improve their margins amid persistently low oil prices. Analysts say Bakken producers tend to have slightly higher break-even prices than Permian producers, though Dakota Access will make many producers competitive in the low US$40-range.

“A lot of us are thinking you have to live in this kind of range-bound world, and that means you have to keep your costs low,” Dundas said.

“Oil-by-rail as a concept is unique. It’s really quite inefficient, but it has definitely served a role during more robust oil prices, where you able to layer on that extra cost. And that is what propelled all of this extra growth in North Dakota.”

Financial Post

Electric car threatens oil’s century-long reign, but change will be slower than the hype

Battery power may have seemed like the future of the automotive sector when William Morrison, a Scottish inventor, debuted his electric car prototype at a parade in Des Moines, Iowa, in 1888.

At the time, the gasoline-powered vehicles entering the market were bizarre, finicky things. They were noisy, emitted a strange odour and required a crankshaft to start the engine. Drivers complained that shifting gears was a nuisance. 

It wasn’t until Henry Ford began mass-producing the Model T, first released in 1908, that the internal combustion engine (ICE) became the cheaper option for consumers. The ICE would go on to dominate the marketplace for more than a century, leaving a deep imprint on everything from the structure of the global economy to the modern design of cities.  

But that dominance could finally be diminishing, in part due to a surge in electric vehicle (EV) sales from automakers such as Nissan Motor Co. Ltd., General Motors Co. and Tesla Inc. Improved battery technology and incrementally lower costs for EVs has in turn propelled the theory of peak oil demand, in which the world’s thirst for oil will soon stop growing, or even taper off.

Companies that generate revenues by digging up and processing the fossil fuel are left to ponder an uncomfortable question: Could the oil industry’s rapid rise end in an equally rapid fall?

Opinions on the potential of EVs widely range from dismissive naysayers to devout believers. But their growing clout has nonetheless raised questions in the oilpatch over what a shrinking market would mean, particularly for the Canadian oilsands where investor returns take longer than in other regions. 

Industry observers say the answer is not entirely clear, especially at a time when it is difficult to separate EV hype from hard data.

“The indicators are contradicting the headlines right now,” said Peter Tertzakian, executive director at Arc Energy Research Institute in Calgary.

Oil is still among the largest power sources on Earth, accounting for 30 per cent of total energy consumption, alongside coal (30 per cent) and natural gas (24 per cent).

Even a sharp decrease in demand for the ICE wouldn’t outright destroy the oil market: only about half of the 97 million barrels of oil the world consumes every day are used for land-based transportation fuels. The rest is used as feedstock in petrochemical plants, jet fuel, bunker fuel, lubricants, heating oil and other products. 

This file image provided by Tesla Motors shows the Tesla Model 3 sedan. Tesla Motors Inc. reports earnings on Wednesday, Aug. 2, 2017.

Some oil executives in Calgary’s corporate headquarters dismiss peak demand theory, or at least see it as too far away to garner any deep consideration. But some major oilsands players, including Suncor Energy Inc. and Cenovus Energy Inc., are envisioning — though not especially fearfully — their business models in a “carbon-constrained” world.

“We do believe that oil demand will likely start to peak within 20-30 years at a level that is higher than today, and although demand will decline thereafter, we expect oil will still be needed for decades,” Suncor’s chief executive Steve Williams said.

Oilsands players have collectively made notable improvements in reducing carbon emissions and other pollutants in recent years.

Canadian Natural Resources Ltd., Canada’s largest oil and gas producer by production volume, cut back its overall emissions intensity by 5.6 per cent in 2015 compared to 2014.

Suncor cut its emissions by nine per cent during the same period. The company hopes to cut its overall emissions intensity 30 per cent by 2030, according to its most recent sustainability report to stakeholders.

Even so, the oilsands are still among the most energy-intensive supplies on the planet, and some analysts wonder if Canada’s heavy oil producers will be the first victims of more rigorous climate change policies. 

“We know that Canadian oilsands are quite carbon intensive, so they could come under pressure there,” said Paul McConnell, an analyst at Wood Mackenzie based in London.

Canadian Prime Minister Justin Trudeau along with Ontario Premier Kathleen Wynne plug in a Chev. Bolt electric car as they were on hand at the Oshawa General Motors Plant to announce 1000 new jobs across Ontario on Friday June 10, 2016.

Since mid-2014, persistently lower commodity prices have helped ready oil and gas producers for a peak demand scenario. Big oilsands companies, as well as smaller conventional producers, have pared costs by drastically reducing their labour forces and moving toward leaner production models.

Unlike the early 2000s, a peak demand scenario would mean that fewer new sources of supply would be needed and less often.

“When you have a plateauing of demand, you’re going to have an environment where price spikes and things like that diminish,” Tertzakian said. 

Big multinational producers, analysts say, would forgo megaprojects in favour of incremental developments to keep competitive in a shrinking market. 

This is already taking place to some degree: companies including Imperial Oil Ltd., Husky Energy Inc. and Suncor are building smaller, lower-cost “replicated” oilsands facilities that can be built in modest 10,000 barrel-per-day stages and repeated. Large-scale developments, by comparison, were often in the 100,000 bpd range. 

Those companies, and others, are also testing new technologies to cut costs and reduce their carbon footprints.

For example, they are injecting products known as solvents into bitumen reservoirs in order to produce oil using less steam, cutting back the amount of natural gas consumed in the process.

They are also installing sensor systems that better predict and monitor choke points and inefficiencies at their facilities, thereby boosting productivity and reducing needless emissions. 

Conventional producers across Western Canada are lowering their per-barrel costs by tweaking old technologies, such as improving their ability to inject high-pressure water into reservoirs to reinvigorate old wells — a process known as “waterflooding.”

They are also piloting new ones, like using more automation in drilling and completing wells, and installing higher-sensitivity sensors that allow geologists to drill the “sweet spots” in oil formations. 

“Every day, there’s a new technology being studied in our offices,” said Grant Fagerheim, chief executive of Whitecap Resources Inc., a light oil producer mostly focused on assets in Alberta and Saskatchewan.

But the debate over EV adoption — and the resulting decline in the need for oil — is more a question of when, rather than if. Bloomberg New Energy Finance, a research group, estimates electric vehicles will become cost competitive with the ICE on an unsubsidized basis as early as 2025. 

Even under such a scenario, however, some argue that rising populations in places such as Nigeria, India and Indonesia could counter any gains in EV adoption in the Western world.

Moreover, a plateau in oil demand around 2025-2030 would hardly eliminate the market for oil.

“That still leaves us with a staggering 100-million-barrel-per-day consumption at that time,” Tertzakian said.

In the near term, EV adoption will be gradual. Globally, there are about one billion small-to-mid-size vehicles on the road today, with about 80 million new vehicles sold every year. Even if every new car sold today were electric, it would take more than a decade to displace the entire global fleet.

“I’m very cautious about saying more rapid adoption can’t happen, because we don’t know what the technologies are going to look like in 2025 or 2030,” Tertzakian said. “But the near-term trajectories do not really support a rapid substitution over the course of the next decade.”

Longer-term projections become much less certain — and could shift much more rapidly.

The International Energy Agency predicts that 54 per cent of new vehicles sales will be electric by 2040, and EVs will make up 33 per cent of the global fleet.

If major centres for electric vehicle sales such as China begin buying EVs en masse, the world could see a more radical shift in the demand for oil, effectively eliminating a massive portion of the oil market in a matter of years. 

The quicker adoption of electric vehicles essentially depends on two factors: battery technology and public policy.

Developing the ideal battery for an electric car is a tenuous balance between cost, safety and energy density, said Linda Nazar, a professor at the University of Waterloo in Ontario who is among the country’s leading researchers of battery technology.

Brand new Tesla Model S cars sit on front of a Tesla showroom on August 2, 2017 in Corte Madera, California. Tesla will report second-quarter earnings today after the closing bell.

Researchers have for years been altering the physical components of batteries in order to maximize their capabilities, creating different combinations of nickel, manganese, cobalt, aluminum and other metals to find more efficient flows of ions between a positive and negative electrode (the basic process by which batteries operate).

But finding the right mix is a painstakingly slow process. A cheaper battery might be less efficient, while a safer and more stable battery might have lower energy efficiency.

“Generally, you have to make compromises,” Nazar said.

But realizing that next step change in efficiency, some believe, is the crucial link in the mass adoption of electric vehicles. 

The other main factor will be policy change.

The U.K., France and some small European countries have already pledged to ban petrol and diesel-based cars over the next few decades. Many others, from China to Canada, have pledged to put regulations or incentives in place to boost EV sales. 

However, critics say many such proclamations are not accompanied by hard policy changes. And in the absence of incentives, sales appear to dry up: Tesla sales plummeted when Hong Kong authorities scrapped a tax break on EVs in February 2017. The removal of the incentive nearly doubled the retail cost of a Tesla Model S. 

But if voters continue to favour tighter environmental policy to wean the economy off oil, EV sales are bound to surge if consumer incentives are offered and charging networks are expanded.

That would bring about a radically different world than the one oil producers have enjoyed for more than 100 years, and will put a hard cap on an industry that has spent most of its time growing. 

In the meantime, oil producers are likely to continue incrementally cutting costs and reducing their carbon footprint, grudgingly preparing for a peak demand scenario, but hoping oil’s century-long reign will hold course.

Rising cost estimates prompt Ontario to rethink private-sector power project

The Ontario government has been struck by sticker shock over the near doubling of the estimated cost of a proposed electricity transmission line, a project awarded to a consortium including Enbridge Inc. and a major pension fund, which chalks up the mounting budget to accommodating tweaks to the plan’s design and timing.

The new $777.2-million estimate for the project’s development and construction has prompted the province to review its necessity amid anger over pricey hydro rates and a plan unveiled earlier this year by Ontario’s Liberal government to lower bills. 

The proposed route of the project, via NextBridge filings.

The proposed project, known as the East-West Tie Line, is a 450-kilometre electricity transmission line that would mostly mirror an existing power line’s path between Thunder Bay and Wawa in northwestern Ontario. 

In 2013, the province tapped a partnership between Borealis Infrastructure, an investing arm of the Ontario Municipal Employees Retirement System pension plan, Calgary-based Enbridge and the Canadian subsidiary of U.S.-based NextEra Energy Inc. as the project’s developer.

NextEra owns 50 per cent of the partnership, called NextBridge Infrastructure LP, while Enbridge and Borealis each have 25 per cent, show filings to the Ontario Energy Board (OEB), a provincial regulator of the electricity industry.

On July 31, NextBridge Infrastructure submitted an application to the OEB for permission to build the proposed transmission line.

Included in the filing is the estimated development and construction cost of the project: approximately $777.2 million, a good deal more than the original estimate of about $419 million.

The filings say the project could increase the average Ontario home hydro bill by approximately 30 cents per month over a 25-year period.

The latest price tag evidently raised eyebrows around Queen’s Park, as Ontario Energy Minister Glenn Thibeault wrote an Aug. 4 letter calling on the Independent Electricity System Operator (IESO), which manages the province’s power grid, to update its “need assessment” for the project.

In doing so, Thibeault cited “significantly higher” cost estimates for the project, which would bolster northwestern Ontario’s electricity supply, especially for the mining industry.

“The scale of the cost increases is very concerning to the Ontario Government and it would be appropriate for the IESO to review all possible options to ensure that ratepayers are protected,” wrote Thibeault, who asked for the findings to be delivered to his ministry by Dec. 1.

Outrage over Ontario’s hydro rates spurred the Liberal government to roll out a plan this spring to lower electricity bills by an average of 25 per cent by July 1.

Steven Stengel, a spokesperson for NextBridge Infrastructure, said costs jumped because of factors outside its control. As one example, the project’s target in-service date was bumped to 2020 from 2018 at the request of the province. 

The project’s design was also updated to better suit the terrain in northwestern Ontario, and the proposed transmission line was lengthened by 50 kilometres “to accommodate Pukaskwa National Park and stakeholder feedback, including First Nations and Metis communities,” Stengel said in an email.

“In spite of these increases, this project continues to present the most cost-effective way to serve the growing power needs of Northwest Ontario,” he said. “The project will create good jobs and economic benefits for the local communities, while expanding the delivery of reliable electricity through the province.”

NextBridge was also awarded the project “under the first competitive bidding process for a transmission line in the province,” the consortium notes on its website.

An IESO report attached to NextBridge’s application said that as of December 2015, the East-West project could provide a net economic benefit of as much as $1.7 billion compared to alternatives. Citing its need, the Ontario government has also dubbed the East-West Tie a “priority” project, smoothing the regulatory approval process.

A CIBC World Markets research report last week cited the East-West project as a “competitive risk” to its price target for Hydro One Ltd., Ontario’s largest electricity distributor and transmitter.

“Ontario’s transmission market has been opened to competition, with the proposed East-West Tie Line awarded to a competitive consortium,” CIBC said.

Parked electric cars are earning money balancing the grid in Denmark

A year-long trial in Denmark is showing that utilities can use parked electric vehicles (EVs) as spare batteries, and those EVs can earn quite a bit of money for their owners from the utilities.

In an interview with Bloomberg New Energy Finance, Nissan Europe’s director of energy services, Francisco Carranza, said that a fleet of 10 Nissan e-NV200 vans has earned €1,300 ($1,530) over the year.

Electricity grids around the world are facing an era of rapid change as more electric vehicles hit the road and as grid supply changes. For grid managers, sometimes small amounts of power are necessary to regulate current frequency and keep the grid working. At the same time, if a lot of electric vehicles draw power from the grid concurrently (for example, when they’re parked at home at night, or when they’re parked at work during the day), that threatens to change how grid operators plan to meet demand, as well.

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