Why Volatile Swings in Electricity Prices are Likely for 2017

This is the second article in our ongoing 2017 Market Outlook Series. Be sure to read part one, “What to Expect from Energy Markets in 2017: A Comprehensive Outlook.”

In the first part of our outlook for 2017 energy markets, we began with a focus on the factors that could impact natural gas and electricity prices in the year ahead, because natural gas plays such a significant role in determining US energy prices.

A strong argument can be made that the direction of alternative energy sources (e.g. nuclear, renewables, storage, energy efficiency, and demand response) in 2017 will have just as great an impact on regional gas and electricity prices.

Changes in nuclear power generation could play an important role in particular. Facing economic pressure from cheap natural gas and renewable energy, roughly one-half of US nuclear plants in competitive markets are at risk of early retirement.

States with pending nuclear retirements have taken two approaches to address this threat to their baseload generation: subsidize nuclear generators, or embrace substitute fuel types.

Illinois and New York have each legislated financial support for nuclear power through zero emission credits (ZECs) in their renewable portfolio standards. These legislative solutions mean higher ancillary costs for ratepayers—which they will see show up in their supply bills.

Michigan, Massachusetts, and New Jersey are each embracing substitute fuel types—and natural gas in particular—as a stand-in for retiring nuclear power. As these states become more reliant on gas-fired generation, they become more vulnerable to weather-related price swings—like those we saw during the notorious polar vortex in the winter of 2014.

Nuclear Generators Facing Revenue Shortfall

Nuclear generators have seen a 25% jump in fuel costs during the past decade. Capital expenses have increased 109%, while operating costs jumped 13% during that timeframe. Even if nuclear retirements in Germany and Japan weaken demand for raw materials and depress fuel costs, significant measures will still need to be taken to keep nuclear power online.

In 2015, leading nuclear executives and the Nuclear Energy Institute (NEI) drafted a plan to cut nuclear generating costs from $35/MWh to $28/MWh by 2018. Industry executives, however, don’t believe that even this 20% cost reduction will save nuclear energy.

Tony Pietrangelo, the NEI’s Senior Vice President and Chief Nuclear Officer, argues that the industry is “not going to cost cut our way out of this problem … [$28 per megawatt-hour] may not be sufficient depending on what market you’re in and where your plant is located.”

Legislation to Protect Nuclear Generation Increases Ancillary Costs

Both Illinois and New York have passed legislation to protect their nuclear generation fleet—and in each case, ratepayers will face higher ancillary costs.

Illinois aims to generate 25% of its energy from renewable sources by 2025. Facing closures from the Clinton and Quad Cities nuclear power plants, the state government passed a $235 million annual subsidy for nuclear generators in a Future Energy Jobs Bill in December. The bill created a zero emission standard that allowed Illinois to purchase ZECs from nuclear plants. Under the plan, Illinois utilities pay nuclear generators for the ZECs, and pass those costs on to their ratepayers in ancillary services.

Also in December, the New York Public Service Commission rejected or delayed petitions aimed to derail New York’s Clean Energy Standard. The standard requires New York to source 50% of its energy from low-carbon sources by 2030, including ZECs. Natural gas and coal generators are currently suing New York over the ZEC program and its benefits to New York’s nuclear program, which are estimated to cost ratepayers 3 to 4 mils/kWh.

Without Legislation, Volatile Natural Gas Could Replace Nuclear Generation

The Rhodium Group estimates that, in the absence of legislative action, over 75% of the lost electricity generation from at-risk nuclear plants would be replaced by fossil generation, largely from natural gas combined cycle power plants.

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According to Sue Tierney, former Assistant Secretary for Policy at the Department of Energy, nuclear retirement means that “electricity prices rise the next day, and emissions rise the next.” As Michigan, Massachusetts, and New Jersey eye pending nuclear retirements over the next two years, ratepayers in these states should anticipate sharper weather-driven volatility in their electricity prices.

Michigan is reeling from Entergy Corp.’s unexpected decision to close the Palisades 725 MW Nuclear Plant in Covert Township. Entergy announced in a press release in December last year that it planned to shutter the 45-year-old nuclear plant in 2018. In the release, Entergy acknowledged that “market conditions have changed substantially” since it bought the Palisades plant from Consumers Energy in 2007.

Denis Palgen, Covert Township’s supervisor, called the plant’s closing “a shock”—surprising because Palisades has power supply agreements through 2022, and the plant’s operating license with the Nuclear Regulatory Commission runs through 2031.

To further complicate matters, Michigan is also facing a series of retirements to its coal-generating power plants over the next six years. Michigan passed SB 437 in November, which preserves energy choice for 10% of the state, but it is unclear whether a stipulation in that bill requiring suppliers to prove capacity two years into the future will undermine the limited competitive marketplace.

Massachusetts is preparing for the 2019 closing of the 680 MW Pilgrim Nuclear Power Station in Plymouth, which generates power for approximately 13% of emissions-free generation in New England.

Matthew Beaton, Massachusetts’ Energy and Environmental Affairs Secretary, admits that the state is “getting to a point now where we’re becoming more reliant on natural gas, just to turn our lights on.” Because natural gas is still primarily used for commercial and residential heating, this reliance spells price volatility for the region.

New Jersey expects Exelon’s 625 MW Oyster Creek nuclear generator in Ocean City to close in 2019. Oyster Creek, one of the nation’s oldest nuclear facilities, provides baseload capacity to approximately 600,000 ratepayers.

The Oyster Creek power plant failed to clear in both the 2014 PJM capacity auction for 2017-2018 and the 2015 auctions for the 2018-2019 delivery year. Exelon argues that “the capacity market alone can’t preserve zero-carbon emitting nuclear plants that are facing the lowest wholesale energy prices in the last 15 years,” but it is widely accepted that PJM capacity payments are vital to the profitability of the region’s nuclear fleet.

Pennsylvania’s 837 MW Three Mile Island nuclear power plant in Middletown is not currently petitioning for early retirement, but it is at-risk. Like Oyster Creek, the Three Mile Island plant failed to clear in the 2015 PJM capacity auction, as well as the 2016 auction for delivery years 2019-2020. Without these capacity payments, Bloomberg New Energy Finance argues, “‘it is very unlikely’ that Three Mile Island will cover its generation costs.” And so Three Mile Island Communications Manager Ralph DeSantis acknowledges that “one option would be the premature retirement of Three Mile Island if prices don’t recover.”

Ohio’s 900 MW Davis-Bess nuclear power plant in Oak Harbor could also look to retire in 2017. Last year, the plant’s owner, FirstEnergy, petitioned the Public Utilities Commission of Ohio (PUCO) for the right to charge ratepayers an extra service fee to stabilize the nuclear generation. PUCO denied the request, but efforts to re-regulate Ohio’s electricity market in 2017 could bring relief to the troubled plant.

FirstEnergy CEO Chuck Jones appears to be banking on that process. At an industry conference in 2016, Jones acknowledged that FirstEnergy has made a decision that “over the next 12 to 18 months we’re going to exit competitive generation and become a fully regulated company.”

Retiring Nuclear Plants Expose Markets to Polar Vortex-like Price Volatility

Electricity markets dominated by natural gas are subject to sharp price swings. Over the past 10 years, natural gas prices at Henry Hub have fallen as low as $1.63/MMBtu and climbed as high as $15/MMBtu. Sparklibrary estimates that at these natural gas prices, “dispatch costs for an efficient natural gas plant would be as low as $18/MWh or as high as $110/MWh.

When nuclear generation is replaced by a fuel source widely used for heating, we can anticipate price swings like those experienced during the 2014 polar vortex to become more routine.

Authored By The Enel X Energy Intelligence Team

The Energy Intelligence team provides talent and knowledge to our customers by making the complexity of energy management simple.

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