The Final Word on Winter in New England’s Energy Markets, Part I: The Difference a Year Makes

Christophe Courchesne

With the sap finally running, the snow slowly melting, and the vernal equinox past, it’s time to look back on winter in the New England energy markets.

Despite dire predictions and some of the worst winter weather on record, there wasn’t a crisis. Modest market shifts made a huge difference, driving down prices, assuring the lights stayed on, and calling into question the wisdom of the region making big new bets on gas pipelines and transmission infrastructure.

In this multi-part series, I will run down the market data on what happened this winter, offer a few explanations, and explore the lessons we should take from the experience as the region looks to its energy future.

Sap buckets on maple trees on a dirt road in Pomfret, Vermont.

Last year, after a very expensive winter in New England’s wholesale energy markets, many were predicting the worst this winter. Ever higher prices. Economic ruin and job losses. Maybe even rolling blackouts on the coldest days. As the leaves were changing colors, electric utilities throughout New England locked in winter power purchases at double the rates most were paying last summer. The newspaper articles and radio stories almost wrote themselves and even went national, as it seemed everyone was talking about energy costs and the apparent culprit—a severe deficit of gas pipeline capacity to transport cheap Marcellus shale gas from the mid-Atlantic and Midwest to heat New England’s buildings and to power our gas-heavy power plant fleet on cold days.

In mid-January, CLF was among the first to see that the supposedly inevitable New England winter energy crisis was fizzling. Natural gas and wholesale power prices were down compared to last year’s prices—way down. Gas from better-utilized pipelines and shipments of liquefied natural gas were amply supplying power plants, even on cold days. Despite higher electric bills, lower oil and gasoline prices were helping many consumers pay less overall for their energy needs than last winter.

Little did we know at the time that February would be among the coldest and stormiest in recorded New England history. While we can expect more weather extremes like this in future years thanks to climate change, February tested the system in ways that, if the pre-winter fears were borne out, would have brought us the full parade of horribles: rolling blackouts, even higher gas and power prices than last year, and major harm to the region’s economy.

In the end, as week after week of cold and snow battered the Northeast, prices in the energy markets did go up. But they didn’t match last year’s peak prices. Here is the final version of my chart showing hourly and daily average wholesale electricity prices on the New England electric grid, comparing last year’s and this year’s prices.

Hourly

(Keep in mind that $10 per megawatt-hour is the same price as 1 cent per kilowatt-hour. Typical homes use between 500 and 750 kilowatt-hours of electricity per month. The prices I’m analyzing relate only to the supply of electricity from power plants; electric bills also include a charge per kilowatt-hour to deliver the power through the transmission and distribution system and other fees and charges.)

In the end, despite the jump in prices in February, the peak weekly wholesale power price in New England was much lower than last winter, and the lowest winter peak in three years. In fact, that peak weekly price—about 15 ¢/kwh in late February—was less than some retail rates that utilities locked in last fall, not just for the winter but for the first six months of 2015. That’s how wrong last year’s predictions about winter prices were.

Weekly

It’s true that the cold drove up February power and natural gas prices, likely making the month the most expensive of the year. As a result, the region’s oil and coal power plants were temporarily able to compete, running more than in other seasons, when they barely run at all. But however you look at this winter—day-by-day, week-by-week, or month-by-month—wholesale power prices were below last year’s prices.

Monthly

Overall, from December 1 to March 20, prices were down 45%. That’s despite the fact that this winter was colder overall than last year, with a temperature in the Boston area about 4°F below historical averages and 1.5°F colder than last year.

These lower wholesale prices mean that it is very likely that next winter’s retail electric prices will be lower than this year’s—power futures for next January and February are now trading between 10 and 12 ¢/kwh, with the other winter months of December and March lower than that. We are already seeing dramatic reductions in retail electric prices for this summer; last week National Grid announced that its supply rate for Massachusetts customers will drop from 16 ¢/kwh to less than 9 ¢/kwh on May 1; this week, the New Hampshire utility Liberty Utilities announced summer rates of less than 7 ¢/kwh, down 55% from its winter rates.

In terms of reliability, the region’s electric grid didn’t miss a beat, despite unfortunately timed outages at the Pilgrim nuclear power plant that took that station offline for many days and the fact that four large non-gas power plants that were available last year—Mount Tom, Norwalk Harbor, Vermont Yankee, and Salem Harbor—are now retired. In the brutal cold and higher priced days of February, ISO-NE never once activated its long chain of alerts and precautions, known as Operating Procedure No. 4, that is triggered when system reliability is at immediate risk.

Why did the markets have such a different winter this year?  I will tackle that question in the next part of this series.

Read Part II of this series: Why This Winter Was Different

Read Part III of this series: Some Lessons from a Calm, Cold Winter

I followed New England’s energy markets all winter on Twitter at #winterenergycrisis. A Storify collecting my best tweets, with more market data and charts, is here.

(photo: Sap buckets on maple trees on a dirt road in Pomfret, Vermont, copyright Jerry and Marcy Monkman/EcoPhotography)

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3 Responses to “The Final Word on Winter in New England’s Energy Markets, Part I: The Difference a Year Makes”

  1. Turner Bledsoe

    So the question derived from these observations is: Can existing energy sources, bolstered by imported LNG, better serve the transition in New England from Fossil Fuels to renewable energy sources rather than bringing in new and expanded “un-natural” gas pipelines. If these pipelines are built to completion the gas will flow to foreign markets as LNG from Canada. What will be the price implication for New England when that happens?

  2. Patricia Martin

    Just wonderful reporting! Thank you so much for digging into this. Now that EE programs can bid for FCM payments, and the State Energy Strategy appendix C notes that an Energy Efficiency rate of 20% is economically feasible, shouldn’t we do that first? EE programs programs identified in an 2014 CELT report, “EE Through 2014,” call for 3300 MW capacity for EE by 2023 for ISO-NE. That’s the equivalent of 8 400 MW gas fired plants…even more if you consider that EE operates at 100% capacity while gas plants are lucky to get 70%.
    NH has not yet established a goal for Energy Efficiency. Doing so would be a great start and would encourage bidders into the FCM market. That means new business opportunities and lots of local jobs. Imagine if we took just $1 Billion, instead of the $4 to $6 Billion proposed for the NED pipeline, and launched Energy Efficiency programs? We would create lots of jobs and ratepayers would see immediate benefit and big reductions in their energy expenses. Same for businesses.
    Appendex C of the State Energy Strategy indicates that it is economically feasible for us to set a goal of approximatley 20% for Energy Efficiency across all sectors. Rhode Island has set a goal (and has FCM commitments) of 19.8% by 2023. NH is currently at about 4% and scheduled to be at only 7% by 2023.
    In the end, I think we’re going to have to figure out a better way to compensate the utilities that isn’t tied to how many KWh are sold. How can we expect them to help us conserve or support residential/community systems if doing so means losing revenue?

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