Now is the time for businesses to lock up their winter electricity pricing.
Despite government and energy officials best efforts to mitigate the problem, the cost of electricity in New England this winter will be largely dependent upon the weather.
The good news is the National Oceanic and Atmospheric Administration predicts a mild winter for the region, meaning the cold snaps that caused price spikes this past winter will be less prevalent.
“The assumption based on the National Weather Service forecasts is that this winter will be milder and have fewer extended cold snaps than last year,” said Jonathan Cogan, senior analyst with the U.S. Energy Information Administration. “If that doesn’t hold true, then the costs will certainly be higher.”
The bad news is the central problem afflicting the region’s electricity costs — constraints in the transmission pipeline that brings natural gas into New England — remains, with short-term fixes not kicking in until winter 2016-2017 and the longer-term fixes taking until winter 2018-2019.
Pipeline constraints limit the amount of natural gas power plants receive. When the extended cold weather hit last winter, natural gas demand for heating businesses and residences spiked, leaving low-cost natural gas power plants unable to get enough fuel. That, in turn, forced regional grid administrator ISO New England to rely on more costly oil and coal plants, causing wholesale electricity prices to spike to $162.88 per megawatt hour in January, an all-time high.
Complicating things this year in Connecticut is the fact that more businesses and residents are heating with natural gas. Plus, two major non-natural gas plants are retiring before year end — the nuclear Vermont Yankee plant and the coal and oil Salem Harbor Power Station — leaving ISO New England 1,200 fewer megawatts to turn to if natural gas plants run short on fuel.
The impact of wholesale prices on ratepayers will depend on who individuals and businesses contract as their power supplier. Companies on variable contracts with alternative suppliers suffered worst last year, as their monthly bills are directly tied to wholesale prices. Those on fixed-price contracts with alternative suppliers fared better, as their monthly bills had the same rate regardless of the wholesale price.
Those using the default utility standard service rate — set by the Department of Energy & Environmental Protection — saw costs go up on Jan. 1, but the price jump wasn’t as great as those on variable-rate contracts.
This issue with wholesale prices is separate from the rate case for Berlin electric utility Connecticut Light & Power, which is applying for a $117 million increase in its distribution reimbursement. While that will impact the distribution costs on ratepayer bills, the wholesale price impacts generation costs.
Regional energy costs going higher
Electricity rates in other New England states have already made headlines for anticipated price spikes this winter. National Grid in Massachusetts said rates will increase 37 percent, based on the higher costs power plants are charging this year. Utilities in New Hampshire have said rates could increase as much as 50 percent.
Connecticut officials say they are confident ratepayers here won’t see those significant price swings. Jeff Gaudiosi — DEEP power procurement manager and the man most directly in charge of selecting the standard service rate — said because Connecticut sets the utility default rate for six-month periods, the winter spikes are better absorbed throughout the year.
Also, because the six-month periods run January through June and July through December, high winter costs are split up, with this December’s pricing already factored into the current rate.
“These are all creative and proactive things that we are doing to deal with a volatile wholesale electricity market,” said Katie Dykes, DEEP deputy commissioner for energy.
Gaudiosi wouldn’t disclose how much the standard service rate will change starting Jan. 1, but said costs will likely be higher than the 8.5-9.9 cents per kilowatt hour businesses currently pay.
Meantime, the utilities — CL&P and Orange-based United Illuminating — file their rate proposals with the Public Utilities Regulatory Authority on Nov. 15. Hearings on those plans start Tuesday and run through Oct. 21. Those rates only apply to ratepayers still using the default utility rate.
Finally, more than 39 percent of all ratepayers — or 610,599 customers — use an alternative supplier for their electricity rates, according to PURA. Those are mostly heavy-use commercial and industrial customers, who are likely to see similar price increases as those using the default utility rate.
Cost mitigation efforts
To mitigate price spikes, ISO New England has expanded on steps taken last year so power costs won’t be so closely tied to natural gas supply.
The New England fuel mix has become less diverse since 2000 when nuclear accounted for 31 percent of all power generated in the region, followed by oil at 22 percent and coal at 18 percent, according to ISO.
Last year, natural gas accounted for 46 percent of all electricity generated in the region with nuclear second at 33 percent.
Coal’s use fell to 6 percent while oil fell to less than 1 percent.
To keep oil plants available when the natural gas plants couldn’t operate due to lack of fuel, ISO implemented its Winter Reliability Program last year, where the oil plants were compensated to keep extra fuel on hand in case they needed to start generating power.
The program expanded this year to liquefied natural gas plants, so the region won’t have to rely on more costly oil plants in the event of extended cold weather, according to ISO.
“The solution that ISO is putting forward needs to include all these capacities, so it keeps the market competitive,” Dykes said.
These measures only are meant to mitigate problems in the wholesale market. The long-term fix is to expand the pipelines transmitting natural gas to New England.
Current pipeline constraints will cause the region’s natural gas commodity costs to increase 6.8 percent this winter, the largest increase in the nation, according to EIA.
Houston-based Spectra Energy is working on small expansions on two of the three pipelines coming into the region to be in-service by early 2017.
In September, Spectra and Northeast Utilities — CL&P’s parent company — announced a $3 billion expansion of the pipeline system, which more fully addresses the problem. That should be finished by late 2018.
Natural gas demand rising
Further complicating matters is that more commercial and residential customers are signing up for natural gas heating. Natural gas utilities Yankee Gas, Connecticut Natural Gas, and Southern Connecticut Gas — all owned by the parent companies of CL&P and UI — now have 576,289 customers, a 2 percent increase over 2013.
Those natural gas heating customers likely won’t see much of a pricing impact on their bills, as natural gas utility rates already are set, Dykes said.
However, they will influence power prices as additional natural gas heating customers take up more space in pipelines bringing fuel to the region, leaving less room for power plants.
Even with more heating customers, EIA is predicting natural gas heating consumption will drop 9.1 percent in New England this winter, largely because NOAA predicts milder weather.
“It is harder to predict pipeline constraints,” Cogan said. “That will likely affect electricity bills in New England.”
CORRECTION: A previous version of this article wrongly attributed the New Hampshire rate increase to NU utility Public Service of New Hampshire, when actually the PSNH rate is decreasing 3 percent while other New Hampshire utilities are increasing their rates.
