Power prices will spike again without change in root cause, utilities say

Last modified: Friday, July 24, 2015

GREENFIELD — After a winter that saw major increases in electric bills across the region, rates have dropped back to more normal warm-weather levels.

While those big fluctuations showed up in monthly electric bills, retailers like Eversource Energy — which are regulated by the state — say they were just passing along hikes by wholesale electricity producers, which aren’t regulated.

And those power generators contend the root cause of the spike in their wholesale power prices — an inability to get enough natural gas into New England — hasn’t changed. That means next winter could bring another roller-coaster ride of price changes.

Against that backdrop, utility officials and government regulators are considering measures to ease the pain, including more frequent shopping trips on the national power supply market and shipping in more liquefied natural gas as an alternative to building a controversial new pipeline.

Last winter, monthly bills increased by about 37 percent for National Grid customers and 29 percent for Eversource Energy users. Eversource’s rates soared to about 14 cents per kilowatt hour from 8.8 cents and National Grid’s to about 16 cents per kilowatt hour from 8 cents.

Those prices were based on wholesale bids Eversource and National Grid got before winter started from power generators around the region. And those bids, say industry officials, are in turn governed not by state regulators but, essentially, by the laws of supply and demand.

Eversource and National Grid serve about 30,000 customers each in Hampshire County. In Franklin County, Eversource has about 28,000 customers and National Grid serves 8,566.

Setting rates

To set their rates, each retail company is required by state law to hold an auction every six months for the power supplied to residential and small commercial customers and every three months for larger commercial and industrial customers.

Once the bidding is completed, the rates are submitted to the state Department of Public Utilities for approval. Regulators must make a decision in five business days due to the volatility of the wholesale electricity market, according to DPU spokeswoman Katie Gronendyke.

Gronendyke said the department can open an investigation into the bidding process on its own if necessary. But this winter, the department determined the price hikes sought by utilities were in keeping with expected market conditions. She said the department has allowed companies to procure electricity through alternative means in the past, but only when it was determined that the bidding process had so few participants that it was not competitive.

ISO New England, the semi-independent nonprofit that manages the region’s power grid, is responsible for monitoring wholesale electricity markets and ensuring that unregulated generators are setting their prices competitively. Though the generators are essentially unregulated, they still have to play by ISO’s rules to participate in the markets. ISO spokeswoman Marcia Blomberg said the organization’s market monitors watch the bids as they come in on an hourly basis, keeping an eye out for anything that doesn’t seem to be in step with expected market conditions.

“Our market monitors know what the price of gas is each day, every hour and we know what it takes to operate each plant and bid competitively. If a generator offers a bid of $13, and the price of gas is $2, that may not be appropriate. We know if something comes in and doesn’t look right,” she said.

If the monitors detect unreasonably high prices or other anti-competitive behavior, the generator’s bid is flagged, a default bid is submitted in its place, and the offending bid can be referred to the Federal Energy Regulatory Commission for further investigation. Depending on the outcome, FERC could impose financial sanctions or other penalties on the generator.

A recent example involved a dual-fuel power plant in Pittsfield owned by the Maxim Power Corp. When bidding into the ISO, the plant told monitors it would be running on oil, a more expensive fuel than natural gas, when it was in fact running on natural gas. FERC eventually imposed a $5 million civil fine against the plant, according to the National Law Review. Maxim argued that it was not manipulating the market, but instead was unsure if it would be able to obtain enough gas to run, so bid in with oil. The issue may go to federal court.

Price watch

In response to complaints about the big winter rate hikes in recent years, Gronendyke said the DPU is now investigating ways to mitigate price volatility in the future. The DPU is considering allowing utilities to solicit bids for residential and smaller commercial and industrial categories more often and average the prices, which could better reflect market conditions and smooth out price changes.

“Increased layering of contracts could potentially reduce price volatility, as the price at any one time would be the average of a larger number of solicitations,” said Gronendyke.

The department is also looking into ways to make it easier for retail electricity customers to find their own power provider.

In filings by Eversource and National Grid with the DPU last fall, the exact numbers received from the bidders have been redacted from public view for competitive reasons. The records show that Eversource signed contracts with four suppliers: DTE Energy Trading Inc., Exelon Energy Generation Co. LLC, GDF Suez Energy Marketing NA, NextEra Energy Power Marketing LLC. National Grid awarded contracts to Energy America LLC, Exelon Generating Co. LLC, Transcanada Power Marketing Ltd. and NextEra Energy Power Marketing LLC.

GDF Suez spokeswoman Julie Vitek said the electricity the company sells to Eversource is generated in this region, with about half derived from natural gas-fired plants in Bellingham, Milford, Blackstone and Waterbury, Conn. The remainder comes from a pumped hydroelectric facility at Northfield Mountain, a river-run hydroelectric generator in Montague and biomass plants in central Massachusetts and northern New Hampshire.

TransCanada owns natural gas and oil-fired power plants in New York and Rhode Island, river-run hydroelectric generators along the Connecticut and Deerfield rivers in Vermont, New Hampshire and Massachusetts, and the 132-megawatt Kibbe Wind Power Project in Maine, according to the company’s website.

NextEra did not return requests for comment, but the company’s website shows that it operates the Seabrook nuclear plant in New Hampshire, the gas- and oil-fired Bellingham Energy Center in Bellingham, two oil-fired plants in Maine, a wind facility in northern Pennsylvania, and three natural gas facilities near New York City and Long Island.

Exelon declined comment, citing a company policy not to comment on wholesale electricity procurement, but the company’s website shows that it owns the gas and oil-fired Mystic Generating Plant, and the Nine Mile Point nuclear plant near Oswego, N.Y. DTE and Energy America deferred questions to ISO New England.

What’s driving the rates up?

Lacey Girard, a spokeswoman for ISO, said the higher rates have followed a dramatic increase in the use of natural gas both in residential heating and electricity generation over the past few years.

In 2000, natural gas produced only 14.7 percent of all electricity in New England, according to ISO data, while oil, coal and nuclear resources produced 57.3 percent of the mix. By the end of this past winter, the data show that natural gas produced about 49 percent of the region’s electricity. By July, it had risen to about 60 percent of the mix. The rise of hydraulic fracturing technology and the resulting boom in domestic natural gas production since 2008 have encouraged a growing demand for natural gas among both gas heating customers and electricity generators as coal- or oil-fired power plants, such as the Mount Tom plant in Holyoke, have retired or converted to natural gas. In December, the Vermont Yankee nuclear plant in Vernon, Vt., went offline, taking an additional 620 MW of generating power with it.

Girard said ISO projections show about 60 percent of new generators will be gas-fired.

Because natural gas is now the primary fuel used to generate electricity in New England, the price of wholesale electricity tends to mirror the wholesale price of natural gas.

Girard said the shift toward natural gas has placed constraints on the system of gas pipelines that feed the region, which she said are not large enough to handle the region’s needs. ISO Vice President of Market Operations Robert Ethier said natural gas becomes more expensive as it passes through each pricing “hub” and as transmission infrastructure becomes more sparse. The Henry Hub in Louisiana sees the lowest prices because of the large amount of pipelines in the area, while New York’s Transco Zone and Boston’s Algonquin Citygate have much less infrastructure and generally see higher prices.

Supplying demand

How to satisfy the growing need for natural gas in the region is at the heart of the current political battle over the Kinder Morgan Northeast Energy Direct gas pipeline proposed to cut through Franklin County from Pennsylvania gas fields to Dracut, near the Massachusetts coast. Many critics contend there are other ways to satisfy the gas needs in winter other than the pipeline, including bringing in more liquefied natural gas or expanding renewable energy resources.

Because utilities that provide gas for heating homes and businesses contract for their gas supplies in advance, while power generators buy fuel in spot markets as they need it, the generators can find themselves paying top price when demand for gas surges in both sectors, ISO says. Laws of supply and demand drive up prices for gas on the spot market where electricity generators operate.

ISO’s Blomberg said the generators don’t sign long-term contracts for gas because it isn’t considered economical — they may not need gas every day.

“Until recently, the fact that power generators didn’t have firm contracts for natural gas delivery wasn’t much of an issue,” Blomberg said. “But as more and more people have converted their heating systems to natural gas, the pipelines are increasingly running at or near full capacity in winter, when demand for natural gas is highest, and most of that gas is being delivered to the LDCs (local distribution companies) for their heating customers.”

That, Girard said, is the situation the generators found themselves faced with over the past few years. According to ISO, the constraints have led the price of natural gas to double for each of the past three winters from an average of $3.97 per million BTUs during the winter of 2011-12 to $18.37 per million for the winter of 2013-14. Last winter, the average price of natural gas dropped to $9.89 per million, though February’s record cold saw it jump to $16.61.

This year’s electric rates were based on the gas spikes that were seen last winter.

Can LNG save the day?

Besides pipelines, using ships and trucks to deliver large quantities of liquefied natural gas is the other way natural gas can reach power generators. Vitek of GDF Suez said the company’s Distrigas terminal in Everett this year saw record imports of the fuel, most of which originated in Trinidad, and that helped keep the price of natural gas down this winter.

“Comparing supplies from the Everett terminal alone from January to March year over year, in 2015 we delivered 21.3 billion cubic feet of LNG to New England. In 2014, we delivered 12 billion cubic feet,” she said. “That LNG, along with that of other suppliers, contributed to a more than 40 percent decrease in the average price of electricity this past winter versus the previous one and a 20 percent decrease in retail electricity prices for thousands of homeowners and businesses in the meantime.”

Ratepayers didn’t see that reflected in their bills until the spring and summer because electric rates were locked in for six months prior to the onset of the winter. In June, the price of wholesale electricity hit record lows, ISO New England reported.

Vitek said GDF believes LNG could serve as a long-term solution to the region’s gas supply issues and the infrastructure needed to store and inject it into the region’s system already exists. She said New England currently has 42 storage tanks and the Everett terminal can store up to 20 billion cubic feet of gas. Stockpiles of LNG could be built up in the summer when demand is low, she said, then burned in the winter.

GDF Suez spokeswoman Carol Churchill said the combined capacity of both the Algonquin and the Tennessee pipelines in Massachusetts is 3.4 billion cubic feet per day. During the summer months, the highest those pipelines have gone is 2.1 billion cubic feet per day, leaving about 1.3 billion cubic feet per day of excess capacity. During peak demand in the winter, she said, the pipelines come close to capacity, but LNG is more than capable of meeting demand during that time.

“It’s absolutely a viable alternative to a new pipeline,” Vitek said. “Currently, power plants that take LNG can and do serve it by injecting it into the pipeline, and that can reach western Massachusetts.”

ISO and Eversource, however, disagree.

“Though LNG plays a vital role in meeting the region’s natural gas needs, particularly in the winter months, increased pipeline capacity is needed in order to deliver abundant, inexpensive, domestic natural gas to the region’s power plants,” said Eversource spokeswoman Priscilla Ress, citing a study performed for the company by consulting firm ICF International.

The study said liquefied natural gas, unlike pipeline-sourced gas, is not generally supplied through contracts and instead travels the globe seeking out the highest prices, regardless of where that may be. That, the study said, can result in higher gas prices overall.

“(LNG) is not necessarily a fuel source that the region can rely on year after year,” Girard said. “LNG is a globally priced commodity delivered by ocean-going tankers, and therefore its availability is very dependent on global prices and need. If the price is higher in Japan or Europe, that is where LNG will be shipped.”

The winter of 2013-14, she said, saw record prices for both natural gas and energy and New England’s prices were the highest in the world, acting as a beacon for those tankers.

Despite close to twice the amount of LNG being injected into the eastern part of the system compared to the year before, the pipelines continued to run at maximum capacity and oil played an equally important role in keeping wholesale prices down, Girard said.

Winter rates, redux?

Ress said it’s still too early to predict whether ratepayers will see similar spikes in their electric bills this winter, but it’s conceivable since the root causes are unchanged.

National Grid spokeswoman Danielle Williamson said the company’s customers should prepare to see hefty electric rate increases again this winter.

“New Englanders should be advised that though power supply costs generally reflect a reduction in bills for the summer months, bills are likely to increase again next winter because of online pipeline capacity constraints,” she said. National Grid has signed on as a customer with Kinder Morgan’s proposed Northeast Energy Direct project and is a partner on another pipeline project in southern New England proposed by Spectra Energy.

“The ISO has made numerous changes in both its operations and its markets to deal with these challenges, but at the end of the day, more energy infrastructure is needed.”

She said that infrastructure could include more pipeline capacity, more electric transmission lines to bring energy in from outside the region, or more storage for LNG or oil. “It’s likely to require a combination of all of the above,” she said.

A project to build a 154-mile-long transmission line under Lake Champlain to bring 1,000 megawatts of electricity to New England from Canada, known as Northern Pass, is currently being reviewed by the federal government. It’s expected to cost about $1.2 billion and would be operational by 2018. Gov. Charlie Baker’s administration is also looking for ways to bring in more electricity from Canadian producers.

Tom Relihan can be reached at trelihan@recorder.com.


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