The United Kingdom and the U.S. Northeast may have something in common going into next winter—a possible energy shortage. Both countries are closing existing power plants—coal-fired and nuclear—in favor of renewable and natural gas generating technologies. In the United States, the Independent System Operator in New England has warned that generating capacity is extremely tight with the future closure of the Vermont Yankee nuclear power plant and several coal-fired power plants in Massachusetts. Likewise, in the UK, 8,200 megawatts of coal-fired power plants have been shuttered, with an additional 13,000 megawatts at risk over the next 5 years. The UK’s energy regulator is worried that the amount of capacity over peak demand next year will be just 2 percent—a very scary low amount for those charged with keeping the lights on.

The U.S. Northeast Power Struggle

Both nuclear power and coal-fired power plants are retiring prematurely in New England due to onerous regulations and competition from low cost natural gas-fired generating plants. The Vermont Yankee nuclear power plant (604 megawatts), which supplies 4 percent of New England’s power and three-fourths of Vermont’s electricity, is expected to retire at the end of this year concurrent with the end of its fuel cycle. Entergy, the plant’s owner, cites a number of financial factors for the retirement including increased costs to comply with new federal and regional regulations and competition from natural gas power plants. However, Vermont Yankee has been opposed by state political figures for some time, and many have cheered its closure after years of criticizing its operation.  Also, U.S. nuclear power plants are plagued with competition from negative power prices from wind energy due to the federal Production Tax Credit (PTC) that provides a 10-year subsidy for qualified wind units. Because Vermont Yankee is operated as a merchant generator, its costs cannot be recovered through regulated cost-of-service rates.[i]

New England expects more than 1,369 megawatts of coal-fired generating capacity to be retired between 2013 and 2016. Dominion Energy Resources is planning to retire the nearly 750-megawatt Salem Harbor coal- and petroleum-fired power plant in Massachusetts this year due to the Northeast states antagonism toward coal (i.e. the Regional Greenhouse Gas Initiative), the costs of compliance of new environmental regulations, and declining profits for coal-fired units in New England.[ii]  To keep operating its coal-fired power plants, the company would need to spend millions of dollars on environmental equipment to comply with EPA regulations. In southeastern Massachusetts, the Brayton Point power plant, the largest coal-fired power plant in New England, is expected to be shut down in 2017 due to EPA’s onerous regulations.

Reliability experts are noting that the New England grid is entering risky territory. It currently gets 52 percent of its electricity from natural gas. There is currently enough natural gas pipeline capacity during non-winter months to supply New England utilities. But, this past winter, the lack of pipeline infrastructure resulted in the need to rely on nuclear, coal, and petroleum to meet demand from the extreme cold weather. The spot price of natural gas was so high that it was less expensive to generate electricity from petroleum. At a recent hearing, Senator Lisa Murkowski noted, “… 89 percent of the coal electricity capacity that is due to go offline was utilized as that back-up to meet demand this winter.”[iii]

With the early retirements of nuclear and coal-fired power plants cutting back on supply diversity, the New England grid is becoming dangerously reliant on natural gas for its generating capacity. The Independent System Operator New England recommended against the closure of the 1500 megawatt Brayton Point facility because the plant is needed to ensure reliability.[iv]

NE Energy Infrastructure

Source: Energy Information Administration,

After the colder-than-average winter, natural gas stockpiles are low. According to the Energy Information Administration, on average over the past five years, natural gas stockpiles totaled 3.832 trillion cubic feet by the end of October going into the winter heating season. This past winter, natural gas inventories dropped by 2.92 trillion cubic feet between the end of October and March 21, making it the fastest pace of withdrawals for any U.S. heating season since 1995. The extreme cold weather pushed stockpiles to their lowest level in 11 years. That large withdrawal means that about 3 trillion cubic feet of natural gas will need to go into storage during the warm-weather months to cover expected winter demand. By the end of October, it is expected that stockpiles may increase to close to 3.5 trillion cubic feet, about 300 billion cubic feet less than the high achieved over the past 5 years, putting even more stress on having adequate supplies for next winter.[v]

The northeast already has the highest electricity prices in the country (outside of Alaska and Hawaii). Residential electricity rates are currently 45 percent higher in New England than the U.S. average. Phasing out these power plants prematurely will only increase electricity rates in New England.

The UK Power Struggle 

The United Kingdom’s electricity consumption is roughly 1/12th of that in the United States, but policies there are leading to growing concerns about energy price and availability. The United Kingdom may encounter power shortages next winter because electric utilities are shuttering coal-fired power plants to comply with Europe’s carbon-emissions rules and have stopped their investment in new generating capacity. Over the past 15 months, 8.2 gigawatts of coal-fired power plants were shuttered and 13 gigawatts are at risk of closing by 2019. According to the UK’s energy regulator, the amount of electricity available over peak demand may drop below 2 percent next year, the lowest level in Western Europe.[vi]

Beginning in January 2016, the European Union will require electric utilities to add further emission reduction equipment to plants or close them by either 2023 or when they have run for 17,500 hours.  Only one UK electricity producer has chosen to install the required technology since the equipment is expensive, costing over 100 million pounds ($167 million) per gigawatt of capacity.   Because the UK has built only one coal-fired power plant since the early 1970s, most of the existing coal-fired plants are expected to be shuttered.

According to data from the Office of Gas and Electricity Markets in London, the capacity margin–the amount of excess supply above peak demand–may drop below 2 percent in 2015. Under normal weather conditions, the margin could drop below 4 percent during the winter months from over 6 percent now, but lower than average temperatures increase electricity demand and would thereby lower the capacity margin further.

The United Kingdom was the first nation to introduce a carbon tax on fossil fuel combustion, which is in addition to the regional carbon trading system of the European Union. As a result, UK utilities are already paying the most among European countries for the right to emit carbon dioxide from burning fossil fuels. To ensure reliability and to remove uncertainty for utilities, the UK government froze the tax from 2016 through 2020 so that electric generator operators could make investment decisions regarding their coal-fired power plants.

Another area of uncertainty for UK utilities is how a proposed market for providing backup electricity will work. According to the Department for Energy and Climate Change, electricity producers will be able to bid in an auction to take place this December to provide backup power for 2018. The program, called a capacity market, is expected to ensure sufficient capacity and security of supply. The Department estimates that the UK power industry needs around 110 billion pounds ($184 billion) of investment over the next 10 years.

According to Deutsche Bank AG, UK power prices, which are one of the highest in Western Europe, are expected to increase by 39 percent in the next five years. The UK generates 12 percent of its electricity from renewable energy today, and plans to get 15 percent from renewables by the end of the decade. UK electricity consumers will pay an additional 120 pounds a year (about $200) to fund the move toward greener power generation on top of their current average electricity bill of 1,420 pounds ($2,376).


The UK and the U.S. Northeast have something in common in their quest for lower greenhouse gas emissions—a possible energy shortage and unreliability of their electricity grid–expected as soon as this coming winter. Shuttering coal-fired power plants in favor of renewable energy and natural gas-fired technology due to government policies and regulations has been the major cause of the concern. Further, government regulations and policies are also closing nuclear units in the United States bringing diversity of supply issues to the forefront. Electric grid operators in both areas are worrying that generating capacity next winter may be too little to meet demand, particularly if frigid weather should hit.

Senator Joe Manchin stated at a recent Senate hearing, “Keep in mind that coal will provide about 30% of our power for at least the next three decades. As you are doing that, think about the fact that nearly 20 percent of the coal fleet is being retired. Add the fact that EPA’s proposed New Source Performance Standard rule will effectively ban the construction of any new coal plants, and you see that our reliability crisis is getting much worse.”

[ii] Dominion News, Dominion Sets Schedule to Close Salem Harbor Station, May 11, 2011,

[iv] Forbes, More Coal Plant Retirements in New England? Perhaps Not So Fast, January 6, 2014,

[v] Bloomberg, Record Natural Gas Need Keeps Bulls Betting on Advances: Energy, March 31, 2014,

[vi] Bloomberg, Green Rules Shutting Power Plants Threaten U.K. Shortage: Energy, March 19, 2014,

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