Rising Utility Costs Lingering After Winter’s Chill Fades
U.S. consumers got a glimpse of rising future utility bills during the winter as coal- and nuclear-plant shutdowns boosted reliance on natural gas.
Demand for gas, used to heat half of U.S. households and generate 27 percent of the nation’s power, reached records from New York to Los Angeles in January, sending regional prices to all-time highs.
Costs surged as a polar vortex and waves of arctic air caused the coldest weather in 32 years. Prices may rise further next winter as 79 coal-fired power plants close because of stricter environmental rules, while Entergy Corp.’s Vermont Yankee nuclear plant was the fifth to announce a permanent shutdown over the past two years.
“For those willing to write off nuclear and coal, this winter should raise a red flag,” said Stephen Schork, president of Schork Group Inc., a consulting group in Villanova, Pennsylvania. “We are setting ourselves up for a massive rally in natural gas.’”
Households in the lower 48 states spent 5 percent more on electricity and 10 percent more for gas on average this past winter, the U.S. Energy Information Administration estimated in a March 12 report. Consolidated Edison Inc. (ED), which owns New York City’s utility, said the typical residential electric bill rose 22 percent to $118 in February from a year earlier.
Natural gas prices are rising even as U.S. production reaches records, thanks to drilling technologies including hydraulic fracturing, or fracking, which make it more economical to tap shale deposits for the fuel. Output at the Marcellus field in the Northeast will reach almost 15 billion cubic feet a day in April, up from 1.49 billion five years earlier, according to the EIA.
Daily power sales in New York averaged $165.24 a megawatt-hour from the end of December to March 24, up 91 percent from a year earlier, based on spot prices compiled by Bloomberg. In the mid-Atlantic states, prices at the benchmark Western hub managed by PJM Interconnection LLC almost tripled, while costs in Texas doubled. Prices this year are highest in Boston at an average $174.45, up 86 percent from a year ago.
Spot gas at the Transco Zone 6 hub serving New York rose to a record $135 per million British thermal units Jan. 21 on the IntercontinentalExchange. Prices have averaged $18.24 so far in 2014, more than double a year ago and the most for the time of year in data compiled by Bloomberg going back to 2002.
In New England, gas deliveries at Algonquin City Gates, which include Boston, surged to an all-time high of $95 per million Btu on Jan. 21 and have averaged $21.29 this year, the most ever for the hub. Gas futures on the New York Mercantile Exchange fell 0.9 cent to $4.402 per million Btu today.
Power and gas price gains in New England this winter may be a snapshot of the future for the rest of the U.S., said Stephen Brick, senior fellow on energy and climate at the Chicago Council on Global Affairs.
About 46 percent of New England’s power came from gas plants last year, up from 30 percent in 2001, according to ISO New England Inc., which manages the state’s grid. No new major gas pipelines have been added to New England in the past 40 years.
Producers in North Dakota are burning off almost a third of the state’s gas amid a lack of pipelines to consuming regions.
The biggest gas price gains were in the Northeast, though pipeline bottlenecks contributed to supply shortages at power plants along the East Coast and in the Midwest, Texas and California, according to regional grid operators.
The weather was the coldest since 1981-82 during December through February in the lower-48 states, according to Commodity Weather Group LLC, which based its estimate on energy-weighted heating-degree days, a measure of weather-driven demand. Gas consumption of almost 3.2 trillion cubic feet in January was the highest ever for a month, Chris McGill, vice president of policy analysis at the American Gas Association, said March 13.
A record number of coal units, 86 generators accounting for 10,308 megawatts of capacity, were mothballed in 2012, while the 79 plants slated for shutdown in 2015 account for another 11,993 megawatts, said M. Tyson Brown, an analyst with the EIA in Washington, who based the estimate on data collected from power producers.
Power from coal-fired plants will account for about 40 percent U.S. electricity generation this year, down from 44 percent in 2009, EIA estimates show. Gas will supply 27 percent, up from 23 percent five years ago.
As many as 13 reactors may be mothballed or retired early, according to IRR Energy data released March 19 in a BNP Paribas SA conference call. The plants account for about 11 percent of U.S. nuclear capacity, EIA data show.
“The market is basically looking at this situation as a weather anomaly,” said Angie Storozynski, a New York-based utility analyst with Macquarie Capital USA Inc. “They aren’t pricing in the tightness of power generation supply sources. A number of these plants won’t be around soon.”
PJM’s installed generating capacity may shrink by 6 percent to 7 percent in 2015 because of environmental regulations, Storozynski said.
While coal and nuclear plants close, gas-fired generating capacity will increase to about 410,000 megawatts by 2016, up 10 percent from 2012, accounting for 35 percent to 40 percent of total U.S. capacity, according to Roshan Bains, director of utilities power and gas at Fitch Ratings in New York.
“As you rely more on natural gas, or one fuel, you will see more and more spikes in power prices,” Bains said. “Rolling blackouts would be more of the norm because of the aggravated fuel supply.”
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