Offshore wind 6 times more expensive than nuclear power when wind’s required battery storage is factored-in
The key item is, “The headline “Offshore wind now cheaper than nuclear power” is very much in the UK news following the latest offshore wind auction in the UK where the lowest bids came in at £57.50 / MWh, well below the Hinkley C strike price of £92.50. But baseload nuclear, which delivers all the time, can’t be compared directly with intermittent wind, which delivers only when the wind blows. To make an apples-to-apples comparison we have to convert wind generation into baseload generation by storing the surpluses for re-use during deficit periods. Doing the math, offshore wind works out to be 6 times more expensive than nuclear power.”
The real strike price of offshore wind
September 20, 2017 by Roger Andrews
Hinkley still scores on reliability and low carbon ….. but the extent to which its costs are obscene is now plainer than ever. In Monday’s capacity auction, two big offshore wind farms came in at £57.50 per megawatt hour and a third at £74.75. These “strike prices” ….. are expressed in 2012 figures, as is Hinkley’s £92.50 so the comparison is fair. As for the argument that we must pay up for reliable baseload supplies, there ought to be limits to how far it can be pushed. A nuclear premium of some level might be justified, but Hinkley lives in a financial world of its own, even before battery technology (possibly) shifts the economics further in favour of renewables …..
Thus spake the Guardian in a recent article entitled Hinkley nuclear power is being priced out by renewables.
What the Guardian says is, of course, nonsense. Comparing non-dispatchable wind directly with dispatchable baseload nuclear is not in the least “fair”. Barring Acts of God baseload nuclear is there all the time; wind is there only when the wind blows. We can level the playing field only by comparing baseload nuclear generation with baseload wind generation, and the only way of converting wind into baseload is to store the surpluses generated when the wind is blowing for re-use when it isn’t. To compare offshore wind strike prices directly with nuclear strike prices we therefore have to factor in the storage costs necessary to convert the wind into baseload, and this post shows what happens to wind strike prices when we do this using the “battery technology” favored by the Guardian. It finds that battery technology does not “(shift) the economics further in favor of renewables”. It prices wind totally out of the market instead.
The two offshore wind farms in question are Hornsea Project 2 (1,386MW) and Moray East (950MW). The project cost for Moray is given as £1.8 billion, or £1,895/kW installed. The project cost of Hornsea Project 1 is given as £3.36 billion, which relative to the 1,218 MW capacity gives £2,759/kW installed. N0 project cost is given for Hornsea Project 2. Moray is 77% owned by EDP Renewables (EDPR) and 23% by Engie. Hornsea is 100% owned by DONG. The locations of Moray and Hornsea are shown below:
To conduct an analysis we have to estimate how much storage will be needed to convert the wind generation from Hornsea and Moray into baseload generation, and to do this we need to know what wind output from these wind farms will be. There are no readily-accessible data for operating UK offshore wind farms, but on the other side of the North Sea are Denmark’s offshore wind farms, and the P-F Bach data base provides hourly generation data for them. So I used Bach’s Denmark data to simulate generation from Hornsea, the larger of the two wind farms, assuming that the results would be reasonably representative. I picked January 2015 as an example month and factored the generation from Danish wind farms in that month up to Hornsea levels relative to installed capacities, which in this case aren’t very different (1,271MW total in Denmark at the beginning of 2015 and 1,386MW at Hornsea). The results are shown in Figure 1:
Figure 1: Hourly generation from Denmark’s wind farms in January 2015 factored up to match Hornsea 2
Strong winds during the first half of the month were largely responsible for the overall 60% capacity factor during the month – respectable for a wind farm. However, the wind blew less strongly in the second half and died away almost to nothing on the 21st and 22nd.
The next step was to convert the spiky wind output into baseload, which requires that surplus generation during windy periods be stored for re-use during deficit periods so that the generation curve comes out flat. Surpluses and deficits were quantified relative to an 825 MW threshold, which is the amount of continuous baseline power Hornsea generates when generation is flat-lined. Figure 2 shows wind generation surpluses and deficits relative to this threshold:
Figure 2: Hourly wind generation surpluses and deficits relative to 825MW of constant baseload output, January 2015
How much storage, which according to the Guardian will be supplied by batteries, will be needed to flatten out these surpluses and deficits? I estimated this in two ways. First I simply accumulated the surpluses and deficits, starting with the batteries discharged, and came up with the battery charge status plot shown in Figure 3. Driven by the generation surpluses in the first half of the month the batteries charge up, reaching a maximum capacity of 95,800 MWh on January 18. Thereafter the deficits set in and the discharges begin, and by the end of the month the batteries are back to being 100% discharged:
Figure 3: Hornsea hourly battery charge status based on accumulation of hourly surpluses and deficits, January 2015
Next I ran the hourly wind generation data through Dave Rutledge’s more sophisticated storage balance algorithm, which starts with the batteries fully charged. The resulting battery charge status plot is shown in Figure 4. 95,800 MWh of battery charge – the same amount as before – is needed at the beginning of the month to keep the batteries charged up until the end of the month, although by the time the end of the month arrives they again have no charge left:
Figure 4: Hornsea hourly battery charge status based on Rutledge storage balance algorithm, January 2015
Beginning with the batteries fully charged, however, creates a complication. During the first half of the month the batteries remain fully-charged for most of the time, and any surplus generation when they are fully-charged has to be curtailed because there’s nowhere to put it. Figure 5 shows the impacts. The curtailment that occurs during the first half of the month amounts to 16% of total monthly generation, and as a result Hornsea delivers an average of only 693MW to the grid instead of the 825MW it would have delivered if the batteries had been discharged rather than charged at the beginning of the month:
Figure 5: Hourly wind generation sent to grid and curtailed based on Rutledge algorithm, Hornsea, January 2015
How to handle this complication? Strictly I should go back and tweak the algorithm until I get an optimum combination of baseload output and battery storage, but in this case it isn’t worth the effort. Why not? Because as we shall shortly see the impacts of the added cost of battery storage on the strike price are so large that even crude approximations are meaningful. So I will run with the 95,800 MWh storage estimate (although it’s almost certainly an underestimate. It assumes 100% charge-discharge efficiency and no battery degradation with time and there is also a high probability that it would increase if time-frames longer than a month were considered.)
Now to economics, and another approximation.
A wind farm gets its fuel for free and maintenance costs are comparatively low; the lion’s share of downstream costs comes from servicing the debt on the initial investment. Here I assume that effectively all of these costs come from debt service, meaning that there will be a direct relationship between the strike price and the initial investment. With this assumption all we have to do to estimate a “batteries included” strike price is add the cost of the batteries to the initial investment and factor the strike price up in proportion. When we do this for Hornsea this is what we get:
Initial wind farm investment = £3.9 billion: I factored the Hornsea Project 1 cost (2,759/kW installed) up in proportion to the increase in installed capacity (1,396 MW for Hornsea 2 vs. 1,218 for Hornsea 1). This gave a total project cost for Hornsea 2 of £3.85 billion, which I rounded up to £3.9 billion.
Cost of battery storage = £35.4 billion: 95,800 MWh of lithium-ion batteries at current prices of around US$500/kWh – £370 at current exchange rates – gives a total cost of 95,800,000 kW * £370/kWh = £35.4 billion.
Cost of wind + battery storage = £3.9 + £35.4 = £39.3 billion
Strike price with batteries included = £579.42/MWh: The strike price increases in proportion to the increase in total investment, i.e. from £57.50/MWh to 39.3/3.9 * £57.50 = £579.42/MWh.
Since as noted earlier the 95,800 MWh storage requirement is almost certainly an underestimate – and quite possibly a large one – we can reasonably conclude that Hornsea’s strike price will be at least six times higher than Hinkley’s £92.50/MWh when the two are compared on an apples-to-apples basis using the Guardian’s battery storage option.
What does this factor-of-six difference tell us? Actually not much, because the comparison is academic. No one is ever going to outlay £35.4 billion to install battery storage at a £3.9 billion wind farm. Backup gas, not battery storage, is presently the only option for smoothing out erratic wind generation, and estimating how much this might add to the Hornsea strike price would be a complex undertaking, although I might give it a shot in a later post.
What it does tell us is that adding even a comparatively small amount of battery storage to a wind (or solar) project could kill it economically, which is probably what motivated the Guardian to make the comment about putting limits on how much “we” have to pay for “reliable baseload supplies”. And in the clean, green, environmentally-conscious, demand-managed, smart-meter-monitored, grid-interconnected, one-hundred-percent renewable world of the future the Guardian envisions we won’t need reliable baseload supplies anyway.
SEP 20 2017
PotashCorp Potash Production Downtime
Consistent with PotashCorp’s strategy of matching supply to market demand and fully utilizing our lowest cost Rocanville facility, we have announced the following potash inventory adjustment shutdowns:
- Allan will curtail production for 10 weeks, beginning Nov. 19, 2017
- Lanigan will curtail production for eight weeks, beginning Dec. 3, 2017
The number of temporary layoffs associated with these inventory adjustments has not been determined, as the company is assessing opportunities for reassigning employees during these shutdown periods to essential services, capital projects, and maintenance activities.
In BHP’s 2017 Annual Report released last night – available here – on page 19 of 296 under item 3 they write:
We are also continuing to investigate one of the best undeveloped potash resources in the world in Jansen in Canada. There are many ways we could realise the value of this project, but Board approval will be sought only if the project passes our strict investment hurdles and is in the best interests of our shareholders.
On page 64 of 296 they write:
Potash is a potassium-rich salt mainly used in fertiliser to improve the quality and yield of agricultural production. As an essential nutrient for plant growth, potash is a vital link in the global food supply chain. The demands on that supply chain are intensifying; there will be more people to feed in future, as well as rising calorific intake comprised of more varied diets. The strains this will place on finite land supply mean sustainable increases in crop yields will be crucial and potash fertilisers will be critical in replenishing our soils.
However, in the near term, overcapacity is likely to get worse. In the 10 years to 2016, the industry added nearly 27 Mt of annual ’nameplate’ capacity. Further greenfield supply will come on-stream over the next five years. As a result, potash prices are currently at their lowest levels in a decade and are likely to get worse before they get better. Although the near-term outlook may be sombre, we expect the peak of oversupply to occur within the next few years. Positive underlying demand fundamentals, assisted by affordable pricing, should see consumption catch up to capacity in the 2020s. Our projections are that demand for potash will continue to grow at a rate of about two to three per cent per year (compound annual growth rate) and that, even taking into account new projects and latent capacity in the industry, demand will outstrip supply within the next decade.
Potash has the potential to create significant value and provide BHP with an opportunity to capture long-term growth and diversification benefits. Our investment in the Jansen Potash Project presents an opportunity to develop a multi-decade, multi-mine business; a potential fifth major commodity offering for BHP. It is consistent with our strategy to own and operate large, expandable assets that deliver value. However, the Project will be presented to the Board for approval only if it passes our strict Capital Allocation Framework tests.
Jansen Potash Project
BHP holds exploration permits and mining leases covering approximately 9,600 square kilometres in the province of Saskatchewan, Canada. The Jansen Potash Project is located about 140 kilometres east of Saskatoon. We own 100 per cent of this Project. Jansen’s large resource endowment provides the opportunity to develop it in stages, with anticipated initial capacity of 4 Mtpa.
Key developments during FY2017
Over the year, our focus was on the safe excavation and lining of two 7.3 metre diameter shafts. Both shafts were safely excavated through the Blairmore formation (which lies about 450 metres below the surface), with steel tubbing in place to prevent water inflow and provide structural support. By the end of FY2017, the production shaft had reached a depth of approximately 730 metres of the design depth of 975 metres and the service shaft had been excavated to approximately 710 metres of its eventual one-kilometre depth. Capital expenditure in the Jansen Potash Project in FY2017 was US$162 million. During the year, we awarded the detailed engineering design contract studying the feasibility of Jansen Stage 1 to Hatch Bantrel, which formed a joint venture partnership to complete this work.
Jansen is in the feasibility study phase and we continue to assess how we can reduce risk and unlock value. The current scope of work was 70 per cent complete at the end of FY2017. Work on the shafts will continue in FY2018. Once shaft excavation is complete, the shafts will be connected underground and shaft infrastructure will be installed. This falls within the current approved scope of work.
Construction beyond the current scope of work will require Board approval. With a later market window now anticipated, the Jansen Potash Project will not be brought to the Board in CY2018. In the meantime, we are considering multiple options to maximise the value of Jansen, including further improvements to capital efficiency, further optimisation of design and diluting our interest by bringing in a partner. Board approval will be sought for the project only if it passes our strict Capital Allocation Framework tests.
SEPTEMBER 20, 2017 / 7:21 AM / UPDATED 35 MINUTES AGO
BRIEF-Encanto Potash secures commitment for C$100 mln funding facility
Sept 20 (Reuters) – Encanto Potash Corp :
* Has secured a commitment for a CAD $100 million funding facility
* Under funding agreement GEM Investments America, LLC and GEM Global Yield LLC SCS undertake to invest up to CAD $100 million over next 3 years
* Proceeds will be used to commence engineering, design phase of mine in anticipation of a shovel-ready construction date of Sept 2019
* Upon a drawdown notice issued from company shares will be issued at a price 90% of market price subject to a $.05 per share minimum Source text for Eikon: Further company coverage:
Hurricane rebuilding in U.S. drives push to ease softwood tariffs
Stacks of lumber are pictured at NMV Lumber in Merritt, B.C., Tuesday, May 2, 2017.
JONATHAN HAYWARD/THE CANADIAN PRESS
SHAWN MCCARTHY AND ADRIAN MORROW
9 HOURS AGOSEPTEMBER 14, 2017
The U.S. government is facing increasing pressure to reach a deal with Canada on softwood lumber, as demand for construction materials is expected to spike higher in Texas and Florida in the wake of hurricanes Harvey and Irma.
While the U.S. lumber industry is dug in on its demand for tariffs, its customers argue that domestic supplies cannot meet their needs, which will drive up the cost of reconstruction in the states that sustained many billions of dollars in storm damage in recent weeks.
The Canadian government is hoping the added domestic pressure resulting from the hurricanes will help pave the way for a deal, Natural Resources Minister Jim Carr said on Thursday.
“We know that [the looming reconstruction] has an influence on markets and on demand,” Mr. Carr said after speaking at the Council of Forestry Ministers meeting in Ottawa.
“And we also know that Canadian producers offer a very good supply of softwood lumber in the United States. That’s an economic reality. Market forces are important, so we think that will almost certainly have some impact on thinking.”
However, during a visit to Washington on Thursday, Ontario Premier Kathleen Wynne said that a resolution to the softwood stand-off currently looks unlikely.
Ms. Wynne met with U.S. Commerce Secretary Wilbur Ross at his office in Washington.
“He didn’t hold out, I would say, a clear hope that there is an easy resolution on the horizon,” the Premier said in an interview at the Canadian embassy.
The two sides were close to a deal over the summer, in which Canada would have agreed to a cap on the amount of softwood it would export to the United States. That quota, one source said at the time, would have been a little more than 30 per cent of U.S. market share to start, falling to slightly less than 30 per cent over five years, then holding steady for another five.
But talks deadlocked over whether Canada would able to exceed its cap in the event that U.S. industry couldn’t produce enough to meet the rest of the demand.
Canada’s Ambassador to the United States, David MacNaughton, said this is still the sticking point in a deal. He pointed out that, as it stands, the United States is importing more lumber from Germany and Russia because it cannot produce enough to fill the market gap left by its punitive duties on Canadian wood.
“We’re right down to the last issue that needs to be resolved, which is what we call a ‘hot-market provision,'” he said in a panel discussion at a Washington event hosted by online news source Politico. “Rather than taking lumber from Russia, why wouldn’t you take it from Canada?”
Mr. MacNaughton accused the U.S. industry of deliberately stonewalling a deal “because they’re making a lot of money right now.
“It’s unfortunate that we’re in a situation where the price of lumber right now is sky-high. It is to the benefit of a few lumber barons. We are ending up in the United States with people not being able to afford to buy new homes or to construct new homes,” he said.
The National Association of Home Builders – which has long opposed tariffs – testified at hearings in Washington this week that the proposed trade action would undermine the reconstruction efforts and drive up the cost of housing.
In a hearing this week, Texas home builder Eddie Martin – an executive of the builders’ association – said that the U.S. industry cannot even meet current demand for some key softwood products. Based on strong demand, average prices for softwood lumber have risen 22 per cent since the beginning of 2016 and some prices are at historic highs, the association notes.
“Moving forward, there is going to be a lot of rebuilding,” Mr. Martin, the chief executive at Tilson Home Corp., said in his testimony. “Tens of thousands of people, like my employees, are going to be in a bad place financially and increases in material costs will have a real and lasting effect on their ability to have homes.”
The chief executive of the U.S. lumber coalition accused Ottawa of using the hurricanes as a “political ploy.”
“American towns, cities and, communities should be rebuilt using American products, American workers, and the American spirit of coming out stronger in the face of adversity,” coalition CEO Zoltan van Heyningen said in an e-mail. “To the extent that softwood lumber is needed to rebuild, there is ample capacity in the United States to supply American wood to rebuild American homes affected by these storms.”
Moody’s Confirms Saskatchewan’s Aaa Credit Rating
Released on September 12, 2017
Moody’s Report States Saskatchewan’s Debt Burden Lowest Among Canadian Provinces
Moody’s Investors Service has confirmed Saskatchewan’s Aaa credit rating, the agency’s highest rating for Canadian provinces.
In its credit opinion update, Moody’s states, “Saskatchewan’s Aaa rating benefits from very strong debt affordability… Saskatchewan’s fiscal planning is supported by comprehensive and transparent financial reporting,” and also commends the province for multi-year fiscal planning.
“Saskatchewan received its first ever Aaa credit rating from Moody’s under our government in 2014,” Finance Minister Donna Harpauer said. “And Moody’s has confirmed that Aaa rating today. Some difficult choices had to be made this year as part of our three-year plan to get back to balance, but these decisions were necessary to keep our finances and our province strong.”
Only two provinces in Canada enjoy a Aaa rating from Moody’s, British Columbia and Saskatchewan. Alberta used to be one of three provinces in the country with a Aaa rating but was recently downgraded.
Saskatchewan continues to have the second-highest overall credit rating among provinces behind only British Columbia, when the ratings of the three major agencies (Moody’s, Standard and Poor’s and DBRS) are considered.
“Saskatchewan’s economy is performing well so far, and for the first time in two years is projected to post positive growth,” Harpauer said. “We will continue to work very hard as a government keep our economy growing because a growing economy benefits all people in Saskatchewan.”
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Canada competition watchdog will not challenge Agrium, Potash merger
Sept 11 2017
OTTAWA (Reuters) – Canada’s competition watchdog said on Monday it will not challenge a proposed merger between Agrium Inc (AGU.TO) and Potash Corp (POT.TO), saying the transaction was unlikely to substantially lessen competition in the fertilizer industry.
The Competition Bureau said it had issued a “no action” letter to the two companies, which announced their plan to combine last year in an all-stock merger valued at $25 billion.
Reporting by Leah Schnurr; Editing by Sandra Maler
Trudeau’s sad legacy: Billions in energy infrastructure spending, scuttled on his watch
Claudia Cattaneo: The last time there was so much heavy handed, poorly thought out federal interference was during the failed NEP in the 1980s when Trudeau’s father was in charge
The Financial Post
September 8, 2017
6:33 PM EDT
Prime Minster Justin Trudeau THE CANADIAN PRESS/Liam Richards
The Northern Gateway pipeline ($7.9 billion), the Pacific Northwest LNG project ($36 billion), and now likely the Energy East pipeline ($15.7 billion) are three privately funded infrastructure projects that would have materially strengthened the economy for decades — and all were scuttled under Prime Minister Justin Trudeau’s watch in the past year.
It’s sad to say, but the last time there was so much heavy handed, poorly thought out federal interference into the energy sector was during the failed National Energy Program in the early 1980s, when Trudeau’s father Pierre was in charge.
The first two projects are gone for good, after frustrated proponents moved on to less-intrusive jurisdictions.
The Energy East project remains in play after proponent TransCanada Corp. said Thursday it would suspend its application for 30 days, however the company suggested it may not build it at all. It’s a reaction to the National Energy Board’s unprecedented decision to widen its study of the project to include the upstream and downstream greenhouse gas impacts of the whole oil industry.
“I believe this was the last straw that broke the camel’s back,” given the many changes already imposed on the project and the $1 billion spent to date, said retired TransCanada executive Dennis McConaghy.
On Friday, the NEB said it has suspended its review of the Energy East and Eastern Mainline projects for 30 days, following the company’s request. During this period, the regulator will not issue further decisions or take further process steps relating to the review of the projects, it said in a statement.
With the 30-day time out, TransCanada may be sending a signal to the federal government to get the NEB to reconsider, and/or to its shippers “that we are closing this thing down and KXL is the last thing out of town,” he said.
TransCanada is waiting for shippers on Keystone XL to recommit after the project was revived by U.S. President Donald Trump, and is also waiting for a route decision by the Nebraska Public Service Commission, the last hurdle before proceeding with construction.
The ball is now in Ottawa’s court to figure out whether the benefits of choking oil and gas development by limiting pipeline construction to meet the Paris agreement greenhouse gas reduction commitments are worth the costs, including continuing harm to the oil and gas sector from Alberta to New Brunswick and to Canada’s reputation as an investment destination.
The blowback Friday suggests many have had enough.
Trudeau should be particularly concerned that Alberta is breaking ranks on Energy East, after making the biggest sacrifice to support his climate change agenda, capping oilsands emissions, accelerating the phase out of coal, and imposing carbon taxes. Clearly, with 100,000 oil and gas workers out of work, Energy East was a step too far even for the left-leaning provincial government.
In a strongly worded statement, Alberta NDP Energy Minister Marg McCuaig-Boyd accused the NEB of “a historic overreach and has potential to impact the future of energy development across Canada.”
“Deciding the merits of a pipeline on downstream emissions is like judging transmission lines based on how its electricity will be used,” she said. “This is not an appropriate issue to include in the review. Additionally, Alberta’s Climate Leadership Plan should satisfy concerns about upstream emissions. Prime Minister Justin Trudeau directly cited this climate plan in his approval of two new pipelines last fall.”
Conservative MP Shannon Stubbs, who shadows natural resources minister Jim Carr, said the Energy East suspension is another hit for workers and their families who depend on energy jobs.
“Throughout the past year, investors have frozen or abandoned Canadian projects and taken all potential jobs with them,” she said. “Uncertainty has pushed capital to south of the border, with less red tape and lower costs. The Liberals’ risky policies are hindering Canadian energy. This is yet another example of how government can literally put oil and gas companies out of business. Minister Carr has commented on this situation, claiming this is a ‘private sector decision.’ But it is actually a direct outcome of Liberal decisions.”
Calgary senator Doug Black, who is also a senior energy lawyer, said the NEB “stumbled” on Energy East and allowed “regulatory creep.”
“I simply do not believe it’s realistic to assess in any meaningful fair way both the upstream and downstream greenhouse gas emissions,” he said. “I don’t know how you do it. I certainly don’t know how you do it fairly.”
Black said there is a real risk that TransCanada will drop the project because it can’t get it done under the NEB’s new rules.
Carr is expected to unveil his government’s final overhaul of the regulatory process, including reforms to the NEB and to environmental assessments, later this fall.
His spokesman, Alexandre Deslongchamps, said in a statement TransCanada’s decision is their own to make.
It’s true that Energy East was once offered an alternative to Keystone XL and that given the oilsands’ investment pullback — due in no small part to Trudeau’s policies — production may not reach the levels once expected.
Yet it’s also true that industry is pursuing many initiatives to reduce its carbon footprint and that the market, not politicians, should have final say on whether to support such a long-term project.
N.B., Sask. premiers, Alberta minister blast regulator’s handling of Energy East
By The Canadian Press
Sept. 10, 2017, 5:52 p.m
Alberta energy minister Marg McCuaig-Boyd. Image: Aaron Parker/JWN
CALGARY — Canadian politicians whose jurisdictions could benefit from a proposed multibillion-dollar oil pipeline are accusing the country’s energy regulator of creating uncertainty about the future of the proposed project.
TransCanada Corp. (TSX:TRP) put its application to build the $15.7-billion Energy East pipeline on hold last week after the National Energy Board said it would consider indirect greenhouse gas emissions in evaluating the 4,500-kilometre pipeline from Hardisty, Alta., to Saint John, N.B.
Alberta Energy Minister Margaret McCuaig-Boyd said having regulators consider so-called upstream and downstream emissions could cast a chill over the future of energy development.
“Deciding the merits of a pipeline on downstream emissions is like judging transmission lines based on how its electricity will be used,” she said in a statement Friday.
“This is not an appropriate issue to include in the review. We believe it would be a historic overreach and has potential to impact the future of energy development across Canada.”
New Brunswick Premier Brian Gallant said shifting regulatory parameters have created a “lack of clarity” and that the federal government should step in to get the review process back on track.
He noted that without the pipeline, crude is often shipped using less safe means, like over rail, and that much of Eastern Canada relies on imported foreign oil, often from countries with less stringent environmental oversight.
“This pipeline would allow us as a country to reduce our dependency on foreign oil,” Gallant said. “Many of the eastern refineries depend on oil coming from countries from around the world and that certainly is a potential risk in the future to our energy security.”
Saskatchewan Premier Brad Wall said in a written statement that Canada is beginning to move away from rational discourse on pipelines.
“Will the federal government apply the same greenhouse gas emissions test to every sector, including auto manufacturing? Or perhaps this is just about oil and gas?
“Whether people like the oil and gas industry or not, in a general sense, does not matter. Oil will continue to be necessary to our survival and way of life for decades, even as the world transitions to cleaner fuels.”
NEB spokeswoman Sarah Kiley said the board typically considers direct emissions from the construction and operation of a pipeline, such as from pump stations and marine terminal activities.
In this case, she said the board broadened the scope of its review of the Energy East and Eastern Mainline projects due to “increasing public interest” in greenhouse gas emissions and the federal government’s interest in assessing upstream emissions associated with major pipelines.
Kiley said upstream emissions include activities before the oil would reach the pipeline, such as emissions created in producing oil, whereas downstream emissions refer to activities once the oil has left the pipeline like the refining and combustion of the oil.
McCuaig-Boyd said Alberta’s climate plan, cited by Prime Minister Justin Trudeau in his approval of two new pipelines last fall, should satisfy concerns about upstream emissions.
Greenpeace Canada spokesman Keith Stewart said the province’s climate plan doesn’t eliminate the need for such an assessment.
“The oil market has changed since 2013 when Energy East was proposed and we need to recognize that the future is in wind and solar energy powering electric vehicles, not new pipelines or the tar sands mines required to fill them,” he said in an email.
Atlantica Centre for Energy president Colleen Mitchell said the new regulations are redundant, and she questioned whether utilities, rail lines or trucking companies will now be asked to consider the emissions of their cargo or how the electricity is used.
“It is beyond the scope of this or any pipeline project to measure that,” Mitchell said. “This puts a chink in the investment viability of projects in Canada.”
She added that the track record for resurrecting projects that are placed on hold is not promising.
TransCanada filed a letter to the NEB asking for a 30-day suspension for the project so it can study how the NEB’s decision on greenhouse gas emissions will affect “costs, schedules and viability.” The request was accepted in a decision late Friday.
The Calgary-based company is calling the changes to the regulatory process “significant,” and warns that the entire project and related Eastern Mainline pipeline project could be cancelled.
It indicated that it may need to record a writedown of its investment in the project, if it is discontinued.
The project’s cancellation would be a blow to New Brunswick, which expected billions in investment and hundreds of jobs as a result of the pipeline, which would end at Irving Oil’s Saint John refinery.
Saint John Mayor Don Darling said he was “very concerned” about the uncertainty surrounding the proposed pipeline.
“To have these storm clouds hovering over the project is very concerning,” he said. “We certainly would call on the NEB to bring clarity to the process and timelines.”