When it comes to the future of nuclear energy, the EPA’s mandate to reduce CO2 emissions from power plants is well intentioned but could result in cost hikes for consumers. Here’s why.
President Obama’s Climate Action Plan, issued in June 2013, outlined a broad array of actions intended to reduce greenhouse gas emissions that contribute to climate change and negatively affect both the environment and public health. One of the plan’s goals was to reduce CO2 emissions from power plants. To do this, Obama issued a Presidential Memorandum that directed the U.S. Environmental Protection Agency (EPA) to establish carbon emission guidelines for modified, reconstructed, and existing U.S. power plants.
From this mandate, the EPA developed the Clean Power Plan (CPP). Applying the Clean Air Act, the CPP directs states to establish standards of performance that reflect the degree of emission limitation achievable through the application of the “best system of emission reduction” (BSER). The BSER is the combination of emission rate improvements and limitations on overall emissions that would reduce emissions from the power sector by 2030 to 30 percent below 2006 levels.
While President-elect Donald Trump has indicated he wants to rescind the CPP, the challenges and political fallout associated with complete nullification could be quite extreme. Conventional wisdom expects that the new administration most likely would weaken the CPP, or replace it with a new, diminished standard.
One of the many criticisms of the CPP has been the EPA’s assumption that carbon-free nuclear power would increase slightly to 98.7 gigawatts (GW) in 2030 from 2016’s 96.8 GW. This is an important assumption for two reasons. First, nuclear’ s carbon-free emissions keep the CPP’s projected compliance costs low. Second, the EPA excludes existing nuclear units from its CPP emission goal-setting calculations.
There is, however, a problem with the EPA’s assumption on future nuclear capacity.
Nuclear plants, which today provide 20 percent of U.S. electric power and 62 percent of U.S. carbon-free electric power, are disappearing – through closures and early retirement – at a faster rate than the EPA forecasted due to a variety of economic, regulatory and political factors. Therefore, to comply with the CPP, new natural gas, wind and solar capacity will need to be installed to replace the dwindling nuclear power capacity. And a heavier reliance on natural gas – historically an energy source with significant price swings often tied to unpredictable weather events – could raise electricity prices, especially in northeastern states, where natural gas supply is very much constrained.
FTI Consulting, using its PLEXOS electricity model, found that current nuclear capacity would need to be preserved for the CPP’s goals to be achieved without a significant rise in wholesale electric prices in the Eastern Interconnection. Stretching from Kansas to Virginia and from Florida to most of Canada, the Eastern Interconnection provides 88 percent of U.S. nuclear generating capacity and is one of the three transmission grids in the United States and Canada (the others are the Electric Reliability Council of Texas [ERCOT] and the Western Electricity Coordinating Council [WECC]).
Without nuclear energy, achieving the EPA’s CPP carbon reduction goals at best may be difficult and may only be achievable by placing significant economic burdens on energy operators, consumers and the U.S. economy.
Challenges Facing the Nuclear Industry
There are currently 61 nuclear power plants (with 99 reactors) operating commercially in 30 U.S. states.
Soon, there will be many fewer.
One vector of pressure on the nuclear industry is economic. Natural gas prices have fallen dramatically over the last seven years. In March 2016, they dropped to their lowest level ($1.57 MMBtu) since 1998. Because natural gas prices often set the marginal cost of supply during peak periods, wholesale electricity prices have fallen considerably, too. As such, nuclear plants have seen their profits squeezed and many nuclear plants are not generating enough gross margin from markets to cover their fixed cost of operations.
Regulatory efforts intended to encourage the development of alternative energy sources represent a second vector of pressure that is problematic for the nuclear industry. Renewable energy tax credits, which are unavailable to the nuclear industry, incentivize the development of solar and wind. These resources alter the supply curve by adding more capacity that is dispatched at no cost, further lowering wholesale market prices and squeezing nuclear profits.
The third vector is political. The 2011 Fukushima incident, combined with environmental concerns about water usage and nuclear waste management, have led to widespread activist opposition to nuclear power. Simply put, nuclear energy is becoming more unpopular with larger swathes of the public and therefore unpopular with politicians.
Not surprisingly, companies are responding to these economic and political pressures by closing nuclear plants – in many cases before their licenses to operate are set to expire.
For example, Entergy closed its 0.6 GW Vermont Yankee plant at the end of 2014, even though in 2011 the Nuclear Regulatory Commission had extended its license for another 20 years. Three additional plants in California, Florida and Wisconsin – with a combined capacity of 3.7 GW – closed in 2013. On Oct. 24, 2016, the Omaha Public Power District closed the 0.5 GW Fort Calhoun plant.
Already announced retirements amount to 8 percent of total current nuclear capacity. Exelon, which had reached an agreement with New Jersey to cease operations at the 0.6 GW Oyster Creek facility by 2019, announced in June 2016 plans to close its Illinois Clinton and Quad Cities nuclear plants in 2017 and 2018, respectively, for economic reasons. The company claims to have lost $800 million over the last seven years on the two plants, which represent 2.9 GW of capacity.
The drumbeat of premature retirements continues, and the shrinking of U.S. nuclear capacity proceeds apace. Entergy announced in April 2016 that it will close the Pilgrim plant in Massachusetts (and its 0.7 GW of capacity) in 2019. In June, PG&E withdrew its 20-year license renewal application for its 2.2 GW Diablo Canyon reactors in California.
Because the EPA did not categorize existing nuclear plants under its “best system of emission reduction,” these plants cannot be counted toward the clean energy mandate, which does not make matters easier for the nuclear industry. (Only the five new reactors under construction and being commissioned will fall under BSER, as compared to 99 reactors that will not.) And the relicensing of existing nuclear plants is precluded from BSER classification as well.
Therefore, in an energy environment in which low-cost nuclear is being replaced by natural gas and renewables, carbon prices inevitably will rise if the CPP’s 2030 emission target is to be met. And given the deteriorating economic and political condition of the nuclear power industry, it can no longer be assumed that all of existing nuclear capacity will endure to provide carbon-free emissions during the CPP compliance period.
At the very least, this calls for a reassessment of the CPP modeling.
Modeling the Importance of Nuclear in Keeping CPP Compliance Costs in Check
FTI applied the PLEXOS electricity model to assess the impact of accelerated nuclear plant closures on electricity prices in the Eastern Interconnection through 2035 under the CPP. We modeled two cases to understand the price impacts of nuclear plant closures under the CPP.
In the Baseline Case, we assumed a nuclear capacity outlook that closely reflects EPA’s assumptions in its CPP modeling. It assumes 2016 nuclear capacity – along with reactors under construction – remains in place through 2035. In the Baseline, recently announced retirements and closures do not occur; new units currently under construction continue as planned in 2019 and 2020, and older plants will remain open beyond 60 years or will be replaced.
In the Alternative Case, we assumed that nuclear units will retire whenever their existing licenses expire; the retirements already announced will occur as planned; nine nuclear reactors considered at risk for political and economic reasons will be closed by 2022; and new units currently under construction will come online as planned in 2019 and 2020.
In the Alternative Case, even if those new units come online in 2019 and 2020, 24 percent of current nuclear capacity will be gone by 2025, and by 2035 only 51 percent of current capacity will remain.
It should be noted that our CPP modeling assumes the New Source Complement provision, where new fossil units are covered under the regulation. Our modeling also does not allow for the trading of emission permits between or among states, nor does it allow for the banking of emission permits.
The Cost of Compliance
Our analysis shows that compliance with the CPP will become much more expensive in the Alternative Case. CPP carbon prices in the Eastern Interconnection would rise an average of 26 percent between 2022 and 2035. And as nuclear carbon-free generation is lost, it will be replaced by natural gas, increasing emission levels as renewable capacity cannot be built realistically with the scale or cost effectiveness to replace the retired nuclear capacity.
In other words, losing the carbon-free energy generated by nuclear plants will increase the cost of CPP compliance. This cost will be passed along to consumers as wholesale and retail energy prices rise, hurting the whole U.S. economy. Wholesale electricity prices in the Alternative Case are 6 to 8 percent higher than the Baseline Case from 2022 to 2032. By 2035, prices are nearly 15 percent higher compared to the Baseline Case.
Based on our modeling, we believe the EPA’s Baseline assumptions considerably understate the CPP’s potential price impacts.
Price increases will be more dramatic within certain regional markets. For example, electricity prices in New York will be higher as the Indian Point, Ginna, and James A. FitzPatrick plants are all assumed to be retired before 2018. Indian Point is operated by Entergy, and its CEO has said the company is assessing all its assets due to “the financial challenges our merchant power plants face from sustained wholesale power price declines and other unfavorable market conditions.”
On average, New York will experience an average 18 percent rise in wholesale prices between 2022 and 2035. Not coincidentally, in August 2016 New York State’s Public Energy Commission proposed $500 million in subsidies aimed at keeping the Ginna and Nine Mile Point plants operating after their retirement dates. The Commission said the subsidies would cost New York utility rate payers $962 million over two years, beginning in 2017. Exelon, which operates Ginna and Nine Mile Point, would receive the bulk of the subsidies and has pledged to invest $200 million in the spring of 2017 if they are approved.
What Can Be Done?
The first step to remediating a problem is recognizing it. The impact of nuclear retirement on stated CPP targets must be met with better data and better modelling.
Next, EPA’s modeling of the CPP should reflect current realities. Subsidies (such as those proposed in New York) will help nuclear operators get through present economic difficulties, but they are temporary and are being challenged in courts. It would be better for EPA to recognize that the current cost structure of nuclear energy in its modeling does not properly compensate operators. It needs to fix that.
Nuclear generation is carbon free. It is unfortunate that the CPP does not recognize that relicensing nuclear plants avoids the addition of fossil fuel-fired power plants. Because it doesn’t, the EPA excludes nuclear plants undergoing relicensing from receiving economic credits for their carbon-free contributions to the U.S. energy system.
Conversely, removing all tax credits would create an even playing field for gas, coal, renewables, nuclear and all other technologies, allowing nuclear to compete more successfully.
These are possibilities, not suggestions, but without some sort of action, FTI Consulting’s analysis indicates that the EPA has underestimated the cost of meeting its CPP goals, and the U.S. economy – and rate payers – ultimately will bear that burden.
Ken Ditzel is Managing Director in the Network Industry Strategies practice in Economic Consulting at FTI Consulting. Rob Fisher is Senior Director in the Network Industry Strategies practice in Economic Consulting at FTI Consulting.
Read the original post on FTI Journal.