This week, Newfoundland and Labrador Hydro president John MacIsaac said the unit was installed to help in periods of peak demand — hours a day, on the worst of days. However, he said it was actually run 24-7 beginning the first week of January through Feb. 27 of this year.
It was not flat out (maximum output is roughly 120 megawatts), but it was never shut down.
“It’s about 12.3 or 12.5 million litres of fuel in January,” MacIsaac said in an interview with The Telegram.
Installed in 2014 and fully commissioned in early 2015, the CT runs on a different fuel oil than the three generators inside the main power plant. While the power plant receives its No. 6 fuel oil via shuttle tanker, the CT fuel is trucked in, accounting for the spike in truck traffic early this year on Town of Holyrood roads.
The CT also costs more per kilowatt hour to operate (21.4 cents versus 10.61 cents for the main power plant units).
Hydro upped use of the CT to help address a problem arising at the start of the year with: (1) low water levels in Hydro reservoirs and (2) mechanical problems in two units in the main Holyrood power plant (leaving it able to supply only 390 MW, versus a usual 490 MW capacity).
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The Holyrood plant’s ability to provide power is down significantly because of problems with boiler tubes in Unit 1 and Unit 2.
Since the start of January, power watches have been issued periodically as Hydro’s production ability has been further impeded at times from various issues, but the de-rating Holyrood Unit 1 and Unit 2 has remained in place throughout.
“Unit 1 and Unit 2 are de-rated to 120 MW each, at present, until we get inside and do work inside this coming summer,” MacIsaac said. Unit 3 is 150 MW.
About 50 miles of boiler tubing has to be maintained in each unit. The plan is to get into Unit 1 and Unit 2 for boiler tube replacement work this summer, and that will inform the capacity of the units next winter.
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On the reservoirs, recovery is considered essential for Hydro planning.
“On an ongoing basis, on a daily basis, it gets very close and careful management, because it’s so critical for us,” MacIsaac said of the water levels.
“It’s about preserving the capacity and the ability to meet customer load.”
Preserving the capacity means for the long-term, as well as for this winter, with Hydro anxious to assure water levels are not a concern over multiple years, as a result of a single year’s shortage of rain and snow.
“As Newfoundlanders and Labradorians it’s very difficult to believe that we’re dry,” he said.
And yet, he said, a lack of fall storms, low general precipitation and lack of snowpack to provide runoff has set Hydro’s system up for a shortfall.
To allow reservoirs to recover, the utility pulled back on its hydro power production in favour of more fuel burning.
The utility made an application in early February to the Board of Commissioners of Public Utilities (PUB) to recover associated costs with reservoir recovery, suggesting it would cost $33.3 million.
With the gift of more precipitation, MacIsaac said, the final bill might not reach quite that high, but there will be a cost.
“It could be $20 million and it could be something less than $20 million, but not appreciably less than $20 million, because we’ve already put the thermal energy in,” he said.
Passing the cost to ratepayers must first be approved by the PUB. Even then, it would be applied to bills over a five-year period.
He noted the troubles of this year are not expected to be an issue when the hydroelectric plant at Muskrat Falls is in service, feeding into the island grid.
“We’re being prudent in the amount of energy we’re adding in. We have targets that we measure against daily and we’re taking steps in order to ensure that we preserve the capacity and the (system) reliability,” he said.
Forecast peak power demand, versus actual
Speaking with The Telegram about N.L. Hydro’s recent challenges, president John MacIsaac made reference to increased demand for power on the Avalon Peninsula since 2010.
As of the end of 2015, peak demand essentially matches with Hydro’s forecast from 2012:
2013: Forecast Peak = 1632MW, Actual Peak = 1651MW
2014: Forecast Peak = 1691MW, Actual Peak = 1714MW
2015: Forecast Peak = 1721MW, Actual Peak = 1720MW
(SOURCE: As published by the provincial Department of Natural Resources in “Electricity Demand Forecast: Do We Need the Power?” November 2012).
