Surry Nuclear Power Station

Should Dominion Energy re-license its four Virginia nuclear power units? The answer depends on your appraisal of solar power, energy efficiency and other alternatives.

Is there a future for nuclear power in Virginia’s long-term energy outlook?

Dominion Energy Virginia believes there is. Nuclear power currently contributes about 30% of the company’s electricity sales, and the company plans to continue generating power from its Surry and North Anna nuclear power stations for decades to come. Nuclear power, the company says, is reliable, provides fuel diversity, and does not emit carbon dioxide — a major plus as Virginia aims to reduce greenhouse gas emissions.

The utility’s 2018 Integrated Resource Plan, which peers 15 years into the future, assumes that the company will renew the licenses to operate the two nuclear-generating units at Surry and the two at North Anna. At the time of the license renewals, the units would be 60 years old. The nukes would continue to operate until they were 80 years old.

But many people think that renewing the licenses is a bad idea. While Dominion expects that refurbishing the four generating units would cost $3 billion to $4 billion, environmentalists and other skeptics suggest that the actual cost could run significantly higher. It doesn’t make sense to spend billions on nuclear power, they say, when solar energy costs less and is getting cheaper every year. While it is true that solar power is intermittent — it generates electricity only when the sun shines — the advent of low-cost batteries and the spread of electric vehicles, they claim, will make it possible to economically store surplus solar power for when it is needed.

Expect the debate to heat up when the Nuclear Regulatory Commission (NRC) begins processing Dominion’s re-licensing request for the Surry 1 plant. Dominion has filed notice of its intent to submit an application for a license renewal by the first quarter of 2019 — less than a year away. The review could take up to three years, and construction several years more.

License renewal for existing nuclear units is distinct from a proposal, also explored in the 2018 Integrated Resource Plan (IRP), to build a new nuclear unit at North Anna known as North Anna 3. Dominion has spent hundreds of millions of dollars in planning and engineering costs to keep that option alive. Estimates of the cost for building the third unit have ranged as high as $19 billion, and the IRP suggests that it would not make economic sense except in the strictest CO2-reduction regulatory scenario that would compel the shutdown of coal-generating capacity. The cost of building a third nuclear unit would be so high and fraught with so much uncertainty that opposition would be formidable no matter what the circumstances.

The re-licensing proposals are a different story. The up-front capital cost, though considerable, would be in the same ballpark as building new gas- or solar-powered generating capacity. Moreover, fuel costs would be more stable and lower over the long run than for the gas-fired facilities. Although there are no hard figures on what the impact on rate payers would be, no one disputes the fact that re-licensing Surry and North Anna would cost a fraction of building a new generating unit.

Flagships of the fleet

The two Surry units became operational in 1972 and 1973, capable of generating a total of 1,600 megawatts of electric power. In the early years the power station had some major operational issues. In 1972, two workers were fatally scalded by steam after a routine valve adjustment. And in 1986, a steam explosion due to internal erosion and over-pressurization injured eight workers, four fatally. But performance has been steady since then. Other than an incident in which a tornado touched down in the switching station, disabling power to the plant’s cooling pumps, Surry has operated largely without incident.

The two North Anna units went online in 1978 and 1980 with a combined capacity of almost 1,800 megawatts of power. The station has operated without major incident, except in 2011 when an earthquake centered nearby caused light damage and triggered an automatic shut-down of the nuclear operations.

The four nuclear units have formed the backbone of Dominion’s electric-generation portfolio. In recent years, North Anna has operated with top measures of efficiency and safety, garnering the highest ratings in inspections by the Nuclear Regulatory Commission every year but two. Surry and North Anna are consistently ranked as among “the lowest-cost producers of nuclear-generated electricity in the nation,” as reported periodically by Platts Nucleonics Week, a nuclear industry newsletter and database, says Richard Zuercher, manager-nuclear fleet communications.

While the nuclear units account for only 16% of Dominion’s nameplate capacity, they generate more than 30% of its total electricity output. That’s because they operate non-stop, twenty-four hours per day, seven days a week, almost 52 weeks a year, going offline only for planned refueling outages every 18 months or the the rare tornado, earthquake or other mishap. The 2018 IRP, as shown in the table above, assumes a capacity factor for the nukes of 96%, which compares favorably to 70% for combined-cycle gas plants, 42% for off-shore wind (assuming the company manages to build a wind farm off Virginia Beach), and 25% for solar. Thus a nuclear facility with a nameplate capacity of 1,000 megawatts generates 8.4 million megawatt hours annually compared to 6.1 million for natural gas, and 2.2 million megawatts for photovoltaic solar.

The assumption of a 96% capacity factor is not unreasonable. Dominion’s six nuclear units, including two at its Millstone station in Connecticut, has exceeded 92% in recent years, achieving 93.7% in 2013 and 93.34% in 2016. In 2017, the company set an all-time high capacity factor record of 95.1%.

Under the protocols of the first 20-year license renewals, Dominion put into effect an extensive equipment-replacement management program. The company inspects and tests equipment periodically to ensure that it functions as designed, and it replaces equipment based on manufacturers’ span-of-life recommendations. In recent years, the company has installed new electric generators, new reactor vessel heads, and new and improved turbines that spin the generator to produce electricity, says Zuercher.

Over and above routine maintenance, the utility expects in the next re-licensing to replace high-voltage electric cabling in the stations and to upgrade instrumentation and controls, which may involve digital improvements to the control room. A big unknown is whether the steam generators will need to be replaced.

The electric power industry refers to “levelized cost” (also called “busbar” cost) as a yardstick to compare the cost of different power sources after accounting for capital expenditures, debt, fuel, capacity factor, maintenance and operations, and expected service life.

How would the levelized cost of electricity coming from Dominion’s re-licensed nuclear units compare to that of gas and solar?

“We don’t have firm numbers … and we cannot speculate on what the cost will be,” says Zuercher. However, he adds, “We do expect that the nuclear generation component in customers’ bills will reflect, as they do now, the value of being one of the lowest cost sources of electricity in our Virginia footprint.”

In the 2018 IRP, Dominion assumes the price of natural gas will roughly double by 2032, undercutting its competitiveness vis a vis nuclear. But Dominion officials concede that the price of natural gas is volatile and that any forecast has a potential for error. A big advantage of re-licensing the nuclear units is to maintain a diversity of power sources. The price of nuclear fuel is less prone to price swings than gas, and the fuel comprises a smaller percentage of the cost of nuclear-generated power.

“We don’t want to put all our eggs in one basket,” says Zuercher. “We want to avoid excessive reliance on any one fuel.”

Another big advantage of nuclear over natural gas is that it emits no greenhouse gases, a vital consideration in the effort to combat global warming. If Dominion failed to re-license its nuclear units, it would have to replace their 3,400 megawatts of capacity with other power sources. In the current regulatory climate, coal is out. That leaves natural gas as the only option for base-line capacity capable of operating all hours of day and night regardless of weather conditions. But natural gas emits CO2 — almost half as much as coal does for the same electricity generated, and that doesn’t count the cost of drilling, collecting, and pipelining gas to the power plant.

Downsides and alternatives

Many environmental groups and social-justice activists in Virginia oppose the re-licensing of Surry and North Anna. Bacon’s Rebellion asked to interview an expert with the Southern Environmental Law Center, but a spokesman said that “due to travel schedules” no one was available.

The Sierra Club-Virginia Chapter also said no one was available for an interview, but a spokesman did state the following:

Because the Sierra Club is unequivocally opposed to nuclear energy, we work to phase out all nuclear, nationwide, as quickly as feasible. This would include not extending the licenses for operating the Surry and North Anna nuclear units.

The national Sierra Club website cites the long-term disposal of nuclear waste, which remains lethal for 100,000 years, as a primary concern. The U.S. has yet to devise a long-term solution for storing the waste fuel. Nuclear, says the Sierra Club, is a “uniquely dangerous energy technology for humanity.”

Bacon’s Rebellion did talk to Tom Hadwin, a former executive with New York State Electric & Gas and also with Michigan-based Consumer’s Energy, who has retired in Virginia and been active in the debate over electric regulatory policy. Having studied the environmental impact of the Palisades nuclear plant in Michigan, he has more than a passing familiarity with nuclear power issues. He opposes re-licensing Dominion’s nuclear units on the grounds of the risk it poses to rate payers.

Hadwin’s first point is that Dominion’s re-licensing cost estimates, like so many estimates given by the nuclear industry, are likely low. Dominion affirmed and reconfirmed to Bacon’s Rebellion that re-licensing the four nuclear units will cost about $3 billion. But in a Sept. 7, 2017, Barclay’s CEO Energy-Power Conference, notes Hadwin, a slide deck used by Dominion CEO Thomas Farrell put the number at “up to ~$4 billion.”

And that’s today’s estimate, says Hadwin. What will the estimate be 10 years from now when it’s time to re-build the first of the four units? Even Dominion concedes that it is uncertain whether the steam generators will need to be replaced. “Whatever the number is now, it’s likely to be quite a lot higher when the money is spent.”

(“We have high confidence in the cost to prepare our nuclear units for an additional 20 years of operation,” says Dominion spokesman Zuercher. “This is based on a good understanding of our equipment and its performance history.”)

Another drawback, says Hadwin, is that the expected life of the re-licensed plant is only 20 years, compared to 40 years for other sources of generating capacity. Amortization of the capital cost over 20 years rather than 40 years would have a big impact on rate payers.

Hadwin argues that Virginia should invest instead in energy-efficiency measures. Citing an American Council for an Energy-Efficient Economy study based on 2015 data, he says major U.S. investor-owned electric utilities shaved 0.89% off retail electricity sales on average through energy-efficiency measures. The pace setter, Eversource in Massachusetts, saved 3.19%. Dominion, tied for second to last, saved only 0.11%.

“We’ve got a 14-year lead time,” he says. “If you started saving 100 megawatts  per year through energy efficiency, which can be easily done because we haven’t done much in Virginia, you’ll replace Surry 1 or 2 by the time their licenses need to be renewed at a cost of 2 to 3 cents per kilowatt hour. The nuclear units will cost four to five times that.”

Another alternative is solar energy. Solar farms can produce electricity at lower cost than nuclear, and the problem of intermittent production is solvable. Dominion’s Bath County facility is the largest pumped-storage facility in the world. It was built to store the energy from excess nuclear power production at night and release it during periods of peak electricity demand during the day. Without the nukes, says Hadwin, the pumped-storage facility could be used in reverse — to store excess solar power generated during the day and release it in the early evening.

Over the next 14 years other storage options will become more viable. The cost of battery storage, used today mainly to make brief, fine-tuned adjustments to grid voltage and frequency, could fall low enough that massive banks of batteries could be used to store excess solar production for several hours until it is needed in the evening.

Also, electric vehicles will become a large part of the automobile fleet within another 14 years, Hadwin says. Car batteries will suck up solar-generated electric power during the day and feed them back into the grid in the evening.

If nuclear power were truly such a bargain, Hadwin adds, Virginians should ask themselves why electric utilities are shutting them down in states where they aren’t guaranteed a return on investment. Nuclear power often can’t compete in a deregulated market. Five nuclear units have shut down since 2013, according to Beyond Nuclear, and of the 100 licensed to operate today, 17 have announced plans, absent state bailouts, to let their licenses expire or otherwise close.

“Would Dominion refurbish [its] units if the risks and costs of the projects weren’t being borne by the ratepayers?” asks Hadwin. “The merchant generators are saying no.”

“There are lots of options, and lots of opinions, and lots of alternatives. We’ll probably end up doing a mix of things,” he says. “The future grid is all about diversity and flexibility. …. These things need to be analyzed, and they need to discussed” instead of simply assuming that one solution — re-licensing the nukes — is the only way to go.

How’s that working out?

Hadwin, the Sierra Club, and various activist groups in Virginia are calling for a radical overhaul of Virginia’s energy strategy in the pursuit of a low-carbon future. The common elements include: (1) eliminating coal, (2) phasing out nuclear power, (3) capping natural gas capacity and blocking new pipelines that would import more gas, and (4) making an all-out commitment to renewable energy and energy efficiency. Until the economics of off-shore wind can be shown to be viable, in Virginia renewable energy effectively means solar energy.

One country in the world has pursued an energy policy very similar to this. Germany has committed to the massive development of solar and offshore wind even as, after the Fukushima nuclear disaster, it began phasing out its nuclear power stations.

A New York Times headline from late last year sums up the results: “Germany’s Shift to Green Power Stalls, Despite Huge Investments.” Since 2000, Germany has spent about $222 billion on renewable energy subsidies with the aim of generating 27% of its electricity with renewables by 2020 and 45% by 2030. However, the decision to mothball its 17 nuclear power stations by 2020 forced German utilities to fall back on coal-fired power, with the result that the country has seen no CO2 reductions since 2010.

Meanwhile, energiewende, the term used for the transformation of Germany’s energy economy, has radically altered electricity flows, creating enormous stresses on the power grid. Both Germany’s solar panels and its offshore wind farms are subject to weather-related disruptions for long periods. The Energy Transition blog describes how these disruptions create transmission-line bottlenecks that Germany has addressed only in part by rerouting electricity through the grids of neighboring countries and throwing their grid strategies into turmoil.

The German wholesale market design does not take into account the existence of … physical bottlenecks. A number of highly energy intensive industries are located in the South of Germany. And as nuclear plants are phased out in the Southern states, more and more electricity needs to be transferred from the North to the South of Germany.

Congestion-related transmission costs as high as 400 million a year have contributed to higher energy costs. Now, according to Clean Energy Wire, Germany’s electricity prices are among the highest in Europe — 29.42 eurocents per kilowatt hour. At current exchange rates, that translates into about 36 cents per kilowatt hour in dollars. That compares to about 10.5 cents per kilowatt hour in Virginia.

Is it different this time?

But Virginia is not Germany. Geography, climate, industries and settlement patterns differ.

Germany embarked upon its energiewende a decade ago, installing an older generation of technology. As Dominion deploys solar on a large scale, solar panels will be more efficient and lower cost than those that Germany deployed a decade ago. Another advantage is that Virginia is part of PJM Interconnection, arguably the forward-looking and efficient regional transmission organization in the country, if not the world, which means it can offset electricity shortfalls by importing power from wind, gas and solar merchants in a 14-state region with a roughly 20% electricity surplus. Finally, in theory, Virginia could learn from the successes and failures of Germany and other nations and states, such as California, that have pursued aggressive green agendas.

On the other hand, there is little prospect of Virginia developing a viable offshore wind capacity for a decade at the earliest. Wind is a natural complement to solar because it can deliver electricity even when the sun isn’t shining. If Virginia depended exclusively upon solar for its renewable power, it would be highly vulnerable to prolonged periods of cloudy weather and especially to snow storms that cover solar panels. As seen in the chart below, published in Dominion’s 2018 IRP, output of its Virginia and North Carolina solar facilities fell almost to zero when blanketed by a June 2018 snow storm. Solar production took two days to recover fully.

This chart from Dominion’s 2018 IRP shows dramatically solar output in Virginia and North Carolina varied before, during and after a January 2017 snow storm.










Such capacity crashes are not a problem when solar accounts for one or two percent of the utility’s power supply. It could be a very big problem if solar accounts for 30%, which is the maximum renewable output that PJM says it can handle, or 45%, which is the renewable goal that Germany has set.

The road ahead

“Nuclear power is the workhorse of our energy fleet and it is here to stay,” says David Botkins, spokesman for Dominion Energy. “Nothing provides … reliable, 24×7, carbon-free, low-cost energy like nuclear. It employs hundreds of people, is the largest single tax-payer in the communities where they are located, and helps educate students in STEM education through the outreach efforts of our visitor centers team. Relicensure is a no-brainer. “

“Our energy system is undergoing a profound change,” responds Hadwin. “The rapid decline in the cost of renewables and other new technologies is undermining conventional methods of generation. We are also adopting smaller, more decentralized sources of generation. The old concept of massive baseload units used to follow changes in demand is being replaced by many flexible methods of having demand adjusted to match changes in supply. … The wisdom of extending the license is not a foregone conclusion and should be fully studied before ratepayers are burdened with the cost.”

In a white paper, “The Uncertain Future of Nuclear Power in the Southeast,” David Hoppock and Sarah Adair with Duke University’s Nicholas Institute for Environmental Policy Solutions note that re-licensing decisions “come at a time of significant uncertainty regarding future electricity demand and the pace and scale of technological change and a time of increasing natural gas dependence.”

The time to start thinking about these issues is now, the authors say. State utility commissions can establish proceedings that request preliminary cost estimates for the operation of older nuclear units as well as information about technical and licensing challenges. State energy plans can express policy preferences on whether or not aging nuclear facilities are safe and economical to operate, how their zero-carbon emissions fit into long-range environmental goals, and what capacity would replace them if they were retired.

Whether nukes are part of the Old Dominion’s energy future or not, the stakes are huge. If Virginians wait until options have narrowed a decade from now, they very well may wish they started the debate earlier.

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37 responses to “Nukes and Renewal”

  1. Rowinguy1 Avatar

    Of course, this will be a complicated economic analysis, but as it stands now, I feel like if the costs do not become exorbitant (such as it becoming necessary to replace large components of several units), Dominion, which seems intent on going for the re-licensing should in fact pursue that.

    A point you didn’t touch on, Jim, but bears mentioning is that in the next several years, Dominion will be retiring substantial quantities of fossil fired capacity. It has recently advised PJM of more than 1,000 MW of such retirements effective later this year. It is also continuing to operate the units at Yorktown only on an emergency petition from the DoE that can be terminated after any 3 month period, but which is likely to be extended until the James River transmission line can be built. So, the ceteris is not paribus, so to speak. There will likely be additional retirements of aging and inefficient fossil units if any carbon regulation comes to pass.

    PJM has capacity requirements of its members and excising 4,000 MW of very cheap (at this point) capacity would be very expensive, it seems to me. As one of the Dominion officers states in your piece, they don’t want to become solely reliant on natural gas. And, while the General Assembly has now extended incentives toward the deployment of solar, due to that technology’s much lower capacity factor, it would take more than 10,000 MW of new solar capacity to replace the nuclear capacity of the 4 nuclear units, I believe. I think they are credited with about 35% capacity factor.

    Tom Hadwin is right that Virginia could do more toward energy efficiency, but I for one am skeptical that we could “save” our way out of this capacity deficit. I also do not share his opinion that solar could be used anywhere near as effectively with Bath County as the nuclear units now do.

    I suppose the skeptic in me would answer the question that you pose at the outset of your essay “Should Dominion re-license its 4 nuclear units” answers itself. The Company wants to do it and no one seems capable of saying to to them. The Legislature will be as accommodating as it always has been and the Nuclear Regulatory Commission does not seem, at least under the current administration, likely to object either.

    1. Rowinguy,

      Most of the fossil units will be “mothballed” not officially retired. They could be brought back into service over several months, if necessary. Although the capacity is significant, the multiple units covered in Dominion’s latest announcement contribute less than 1% of the total system energy output.

      This raises no concern in terms of reliability. There is an abundance of capacity in PJM at far lower prices than what can be produced by these aging fossil-fired units. This is a cost-saving measure for Dominion.

      There is a difference between pumping up the Bath reservoir at night and discharging it during the day versus doing it the other way around. But this is mostly due to the energy pricing on- and off-peak. Electricity produced by a solar unit is just as effective at pumping up the reservoir as electricity produced by a nuclear plant. You can’t distinguish where the energy came from once it is in the grid.

      I will answer your “can we save our way” to this capacity in my response to Larry.

    2. Good point about PJM’s capacity requirements, especially in the context of the likely closing of additional fossil fuel capacity (presumably coal-fired units and aging gas units). Do we know what those capacity requirements are? Do we know how much capacity Dominion is planning to shut down, and the schedule for those shutdowns?

      1. Rowinguy1 Avatar

        Bremo Units 3 & 4 totaling 227 MW
        Bellemeade Combined Cycle 1 totaling 265 MW
        Possum Point Units 3 & 4 totaling 317.7 MW
        Chesterfield Units 3 & 4 totaling 262.1 Mw
        Buggs Island (Non-utility generator under contract to DVP) 138 MW

        Additionally, a late-breaking item, Ohio-based First Energy Solutions announced the imminent retirement (within next 2-3 years) of 4 nuclear generators, comprising nearly 4,000 MW of capacity, and simultaneously filing an action with the U.S. Department of Energy asking for an emergency order from that agency directing PJM to increase the payments for the capacity from those units, alleging an imminent threat to grid reliability. Something else to keep an eye on. I bring this up only to further make my point that there are retirements all over PJM, not only the DVP owned or operated units listed above, that will need to be considered.

        I agree with Tom that in the overall scheme, the DVP retirements noted above will not hurt PJM’s ability to deliver capacity–now. However, it seems to me that keeping relatively low-cost nuclear on line in Virginia makes sense, particularly since these units seem to continue to be in the money.

      2. Let me underscore what TomH said: “There is an abundance of capacity in PJM at far lower prices than what can be produced by these aging fossil-fired units.” The PJM capacity requirement applies to all LSEs: every LSE must own, or have under contract, somewhere on the PJM grid, generating capacity that’s in-service in a total amount equal to the LSE’s forecast annual peak load plus reserves. A mothballed unit is not “in service.” But there is plenty of independently-owned capacity in PJM and capacity rights can be purchased directly or in the PJM capacity market for a lot less than the cost of un-mothballing one of those old DVP coal plants, which would mean fully staffing the plant and maintaining it on standby, ready to run if dispatched by PJM.

        I would agree with Rowinguy1 “that keeping relatively low-cost nuclear on line in Virginia makes sense, particularly since these units seem to continue to be in the money,” IF in fact the necessary license renewals could be obtained economically. But that, I doubt. The bane of nuclear power has always been changing NRC regulations — often requiring expensive, unforeseen equipment changes and upgrades during and post construction. In addition, the DVP units are now already beyond their originally planned useful lives so some upgrades are needed just to keep things going as originally designed, or to take advantage of technological improvements over the 40+ intervening years. There comes a time when it’s more efficient to start over with a new heat source, if not an entirely new generating plant, and today that would probably not be nuclear powered.

        1. Rowinguy1 Avatar

          I agree absolutely that there comes a time when it is more efficient to start anew and we should have every opportunity to understand the analytics of the decision DVP appears to have made before we are left holding the bag if it is a flawed decision.

  2. LarrytheG Avatar

    I’m a skeptic that we can only build solar and be assured of 24/7 reliable power. Something has to power the night and at this point in time, it’s not batteries and its not electric cars.

    but here are a couple of questions:

    1. – If nukes are so “good” why do they not power islands that right now have to depend on diesel generators for power?

    2. – If solar is so good and “ready for prime time” – why are there almost no islands in the world that rely primarily on solar and utilize those diesel generators to power the night?

    the truth of where we are right now – is found, I think, in the answers to those two questions.

    can we, should we, implement more and more demand-side conservation. Sure we should… that’s a no brainer but UNTIL we actually do it and actually start to see dramatic decreases on power demand – we should not be saying/believing that solar is the answer.

    I want to see solar out the wazoo … build it everywhere but as Germany and California and others are finding out, you cannot power the grid with only solar.

    Needs to also be recognized that North Anna does sit on an earthquake fault. No amount of happy talk will change that reality – and the reality is that North Anna may be one strong quake away from closing.. and closing in such a way there is no short term Plan B other than for Dominion to rely on PJM to make up the shortfall if it does go down.

    1. Larry,

      I am afraid you misunderstood what I was saying in Jim’s article. Here it is in a nutshell:

      PJM forecasts that Dominion Energy Virginia’s load growth will be essentially flat for the next 15-20 years, including new data centers.

      In 2032 and 2033, the Surry units will reach the end of their 60-year license and must be refurbished or retired.

      In 2038 and 2040, the North Anna units will reach the end of their 60-year license and must be refurbished or retired.

      Option 1:

      Immediately begin a program of improving energy efficiency in Dominion’s service territory. If we were able to achieve the annual average energy efficiency improvements of a group of 51 utilities and perhaps improve over time to just half of the energy efficiency improvements that the top utilities are currently achieving, over 22 years, we would displace the need for about 3400 MW of nuclear generation (the total capacity of Surry and North Anna).

      Cost to Ratepayers – Zero

      Energy efficiency has a 100% capacity factor and totally replaces baseload generation. Although an initial investment is required for energy efficiency projects, the savings are greater than the investment so there is no net cost.


      Refit the nuclear units so that they are safe to operate during years 60-80. The original components were designed for a 40 year period of operation.

      Cost – Ratepayers would be required to pay about $10 billion

      This is a rough calculation. It assumes that Dominion’s $3 billion estimate is accurate, even though we are decades away from when the money will be spent, and the NRC has not conducted a hearing and safety analysis to identify what must be done. And we will ignore the 50+ year history of nuclear facilities in the U.S. where final costs for nuclear facilities are always significantly more than original estimates (see Summer and Vogtle as the most recent examples).

      If the total project cost is $3 billion, the current rate structure would provide over $6 billion in profit to the utility, and in addition to repaying the initial investment, the ratepayers would also have to cover the financing costs, conservatively estimated at $1.5 billion. All for only a certain operating life of up to 20 years.

      No contribution from solar units is required. However, for the doubters that a fraction of energy efficiency gains that are currently being achieved in many states today could be replicated in Virginia, the 5000 MW of solar that the new energy bill incentivizes Dominion to build could also contribute to replacing the nuclear capacity.

      The Warrenton, Brunswick, and Greensville units are more than enough to meet the remaining baseload requirements. Mt. Storm would also be available for higher usage periods.

    2. Islands won’t build nukes because nukes generate far more electric power than most islands will ever need. Furthermore, while nukes might arguably make sense for base load capacity, they can’t handle fluctuations in demand, so any island will need a power source that can dial up and down as demand dictates.

      I’m surprised to see that more islands don’t use a combination of solar power and gas-fired turbine generators, or in the absence of an ability to import natural gas, oil-fired generators that can fill in the gaps.

      1. That is exactly what the Kaua’i Island Utility Cooperative does. They have a 120 MWh battery storage facility associated with a 52 MW solar array built by Tesla. Another larger facility is under development. The remaining energy is provided by a naphtha-fueled combined cycle unit and multiple diesel-fueled generators. All fuel has to be imported to the island, which makes it very expensive. Solar plus storage is the low-cost solution for them.

  3. Owners of many nuclear plants that must exist in a competitive wholesale price environment are finding that they cannot compete with the abundant, low-cost supplies of electricity that are available today. The costs of nuclear generation are often too high even without the added costs of refurbishments for an extended life.

    Three nuclear stations will continue operation in New York for a few more years because of $500 million in subsidies from New York ratepayers.

    Several nuclear plants in Ohio were able to wangle several hundred million dollars in subsidies from the state legislature.

    Dominion has threatened to close its merchant nuclear plant in Connecticut, if they don’t receive a subsidy. The Millstone plant is considered by the Wall Street Journal to be the most profitable nuclear plant in the nation.

    Surry and North Anna will not be the “low-cost” providers of energy that they have been if they are saddled with RACs to extract the $10+ billion from Virginia ratepayers.

    The subsidy that will allow the continued operation of Dominion’s nuclear units will be provided by us.

    There should be a thorough discussion of the re-licensing option but it must be a transparent one based on the true costs of that alternative, not stories for the media.

    These units are being proposed to generate a long-term stream of revenue and profits for Dominion. They are smart people, they see the decline in their business model and this is the best choice that they see.

    We need to give them a way to be financially healthy without charging us for projects that we don’t need. We can’t just tell them no, without creating another alternative that works for them and us.

  4. Steve Haner Avatar
    Steve Haner

    Thanks for digging into this, Jim.

    Missing from the discussion is the cost of retiring the plants, which will also be substantial. What is the net cost of a “close or extend” decision? In the short term it might make more sense to spend dollars to renew the plants than to spend a similar amount of dollars to retire them. Short term thinking is often stupid. Perhaps that cost of retirement will also grow with another 20 years. It needs to be part of the discussion. You can’t just shutter the plants and walk away.

    The SCC is the forum where this decision should be made. Be on the lookout for efforts by the utility to move the decision to the General Assembly where it can dictate the outcome or somehow protect its stockholders. Somehow the GA never gives any part of the bill or the risk to the stockholders. N E V E R.

    There is a good chance that North Anna’s renewal will be complicated by the earthquake, even though the plant weathered that challenge well. I think the greater problem is the lack of a long term storage solution for the spent fuel, or acceptance of some form of reprocessing, and that stands in the way of approving either application. My main concern about a decision to extend the plants is economic, and perhaps it makes economic sense, but the current practice of storing the spent fuel on site is also (stupid) short term thinking and it makes no sense to keep growing the pile and leaving it there for centuries.

    1. I wondered about the cost of retirement. Thinking that the nukes are more than 40 years old, I wondered if Dominion had amortized the cost of the original investment. Dominion didn’t get into details, but said that it still carries the cost of major equipment replacements on its books. So, yes, if Dominion had to close the plants tomorrow, it would take significant write-offs.

      Of course, the fact that Dominion continues to make large capital investments in its nukes cuts two ways. The $3 billion to $4 billion estimated cost of re-licensing the four nuclear units does not reflect continued, ongoing capital spending on the plants. I have no idea how much that spending amounts to.

      1. Determining how to treat the life extension cost of a nuclear plant for ratepayer purposes is extremely complex. On the capital side, it’s not just a straight investment followed by 40-50 years of amortization. Nuclear units always include a pot of dollars for decommissioning costs; and even those are based on assumptions that everyone knows are unrealistic, thanks to the federal government’s refusal over many decades and despite many promises to take the storage of nuclear waste seriously. Then there’s the regulatory-imposed obsolescence factor: no other technology exposes the investor to such a risk that, over the course of a short term operating license, conditions will change enough to make another renewal infeasible — each renewal must be viewed financially as perhaps the last.

        Even if the NA units were closed, much of DVP’s investment in the plant site, with its radiating network of 500 kV transmission lines, will remain a useful sunk cost. Undoubtedly the plant, complete with on-site cooling water, would be used again for new generation construction. The question is why extend as nuclear; why now; why at ratepayer rather than shareholder risk?

  5. Peter Galuszka Avatar
    Peter Galuszka

    For a basic problem look at the Summer plant in South Carolina. It went bust when expansion costs went through the ceiling — $25 billion and now Dominion is trying to buy its owner despite a swarm of financial issues and questions about whether South Carolina will be left holding the bag.

    Curiously, the units were to use Westinghouse AP1000 a relatively new reactor design that had huge cost overruns. And, taking history back a long way, Westinghouse put in pressurized water reactors at Surry way back in the late 60s and early 70s. Westinghouse was a pioneer in PWRs and cut its teeth with the nuclear Navy going back to the 1950s and 1960s. So, you have a design history that stretches maybe 60 plus years.

    No one built nukes after Three Mile Island and by the time they got around to it, Westinghouse had been bought by Japan’s Toshiba. That was a disaster and Westinghouse filed for bankruptcy last year. The South Carolina nukes are just lying around.

    I would think cost would be a huge negative and not just whether the SCC will let DOminion pass along costs. WIll the financial market support the idea? After South Carolina and Fukashima?

    Or even earth quake prone North Anna? JAB wrote a fairly positive item about North Anna and the 2011 earthquake. I felt he downplayed a lot of negatives including the fact that the station was shut down for months, it sparked safety upgrades to other nukes nationally and that the Louisa area quake was so powerful that stored nuclear waste containers at North Carolina that weighed a number of tons were actually moved around by the tremors. Not good!

    I’m not a nuclear engineer but I do wonder how wise it is to keep 60 year-old nukes running for 60 more years. Radiation bombardment weakens critical structures. Is there some kind of brilliant new design out there? If so, why wasn’t it used in the Palmetto State. Lastly, we still (STILL) haven’t resolved the disposal of all the waste these gizmos produce. Just kick the can 60 years down the road?

    1. For purposes of clarification…. The Summer nuclear unit in S.C. was new construction, right? I can’t imagine that Dominion would ever get permission to build a third unit at North Anna at a cost of ~$19 billion. But that’s a very different animal than re-licensing an existing plant.

      1. Rowinguy1 Avatar

        Yes, Sumner was a new plant. I don’t believe it’s costs have risen anywhere near the $25 billion Peter cites, but nevertheless they ballooned way beyond initial estimates and the construction has been halted. The Plant Vogtle units in Georgia remain under construction and are pushing about $20+ billion (there are 2 units being built there) when the initial estimates were about half that.

      2. The estimate to complete the Summer plant was $25 billion. That is why it was cancelled. It was not possible to produce electricity at anywhere near a competitive price from this project.

        If the state regulator and policymakers had asked the right questions and demanded accurate answers, not optimistic forecasts, they would have known this from the beginning and avoided a great deal of economic pain that is being heaped on ratepayers of SCE&G. Even if the buyout by Dominion goes through, they will continue to have the highest residential rates in the region and in South Carolina by far.

        1. Rowinguy1 Avatar

          As of December 4, 2017, according to this article:

          the two utilities building that facility had spent $9 billion and were then looking at least an additional $4.7 billion to finish it. So, not $25 billion, but a hell of a chunk of change.

          1. The article that I had was from Power Magazine last July. They said that Santee Cooper had invested $4.7 billion up to that time and the estimate was that the total cost of completion for Santee Cooper’s 45% share would be $11.4 billion, including interest costs during construction. Factoring in SCE&G’s 55% share would bring the completed cost for the entire project to over $25 billion.

          2. Rowinguy1 Avatar

            Replying to Tom below. I saw a similar $25 billion figure quoted by Santee Cooper officials last July, also reported in the Post and Courier, a South Carolina Paper, but the engineering estimates in December scaled that back quite a bit.

            I guess when you’re explaining to your regulators why you are abandoning ship, it make more sense to maximize the avoided costs.

  6. Decommissioning a nuclear plant is a significant undertaking and very expensive. When Dominion closed its Kewaunee nuclear plant in Wisconsin in 2013, they estimated it would cost $937 million to decommission the 556 MW plant.

    Every year of operation nuclear plant operators must set aside a certain amount and put it in “escrow” just for this purpose. These funds are paid for by ratepayers or out of the revenues of merchant plants and cannot be used for any other purpose. As such, they are not identified as cash assets on financial statements until a plant is retired and the decommissioning begins.

    I believe the DOE halted the requirement that money be set aside for this purpose a little while ago, but I am not certain of the details.

    My point is, companies do not avoid retiring nuclear plants because they don’t want to spend the money. The funds already exist for this purpose and would not be a new expense unless the ultimate cost exceeds what has been set aside.

    There is no permanent solution for long-term disposal of the used fuel and the highly radioactive portions of the plant such as the reactor vessel, steam generators, spent fuel pools, etc. Our current solution is to just keep it all in place and let somebody worry about it later. One good financial meltdown would greatly hobble our ability to deal with this issue.

    We have significantly radioactive materials scattered around the U.S. at the 100 reactor sites. Some of the used fuel has been encapsulated in a solid form, but we are far from a reasonable solution. We have had nearly 60 years to work this out. But we are farther away from an answer than we were a decade or so ago.

    The weapons grade waste is being stored in Carlsbad, NM. They had a radioactive release there a few years ago.

    You should see some of the innovative ideas for surface warning devices that would still work for cultures that might exist tens of thousands of years from now who might have lost information about our history and our language. What would you design to say “Don’t dig here” to someone 10,000 years from now?

  7. As always, the issue is that high cost is no problem for Dominion because rate payers must pay the cost plus profits.

    We need some kind of independent review. Meanwhile Dems are convinced Virginia, despite very low carbon emissions, must nonetheless join RGGI the Northeast states committing to go to zero carbon emissions. So Dominion has defacto strong support from the Dems to continue with zero carbon approaches- no matter what the cost.

    Presumably a more liberal Virginia will defer to PA, WV. and OH as far as generation of power.

  8. TooManyTaxes Avatar

    I’ve been reading a bit about blockchain technology/applications. While I don’t fully understand the concept yet, it looks to offer major improvements in security for electronic transactions but also is reported to require substantial amounts of electricity. Do demand estimates take into account the potential demand from blockchain growth? I still wonder whether we are properly considering demand growth from electric vehicles and the installation of 5G radio equipment.

  9. TBill,

    The RGGI group of states does not embrace nuclear power as a long-term solution to reducing carbon emissions, although New York was willing to provide a short-term subsidy of $500 million for three nuclear units to maintain zero-carbon generation from the nukes while their energy efficiency programs eventually replace them. New York is now forecasting a long-term demand curve that will decline 0.9% per year. Massachusetts expects that 20% of their generating capacity will be provided by energy efficiency in 2020.

    This approach has reduced energy cost in the RGGI states by $2.3 billion in just the last seven years. A drastic difference compared to adding $10 billion for refurbished nuclear units compared to $0 net cost for efficiency in Virginia.

    But the utilities in the RGGI states have generation that is decoupled from the retail side. They do not need to build more to earn more as the Virginia utilities do.

    1. By the way, if Virginia became the 10th state to join RGGI, the estimates show that we would contribute 40% of the group’s total carbon emissions. I was surprised by that.

      1. Tom- I’d be surprised too but I’ll check Clean Power Plan numbers, if I still have them. But I’ve been saying this RGGI is a group committed to importing energy from Canada and other states.

        1. TBill – you are right. In New York we imported cheap hydro for decades from Canada. It’s still going on and is expanding. We had a good deal of our own hydro from Niagara Falls, small mountain units, and from the Hudson, but the low-cost plentiful supplies from Canada were too cheap to pass up.

          Look at it this way though. Let’s say a state has an internal capability to generate 100 units of electricity within its boundaries, and currently has a demand for 120 units. There are a couple of ways of dealing with the issue:

          The Virginia way – invest in more conventional generation, such as:

          1. Gas-fired units with a 40 year life, an increasing cost trajectory for fuel and added emissions. Ratepayers repay 3- 4 times the cost of the unit to the utility which must be repaid regardless of how much the unit is used. Or,

          2. Refurbish an old nuclear unit for 20 years of operation. No additional emissions but an increasing cost trajectory for fuel (but not like for gas). Pay at least 4-times the cost of the project to the utility. Refurbished units now generate electricity at a cost far higher than could be obtained by other means.

          Or –

          The RGGI way –

          Purchase the extra 20 units from the large surplus of low-cost generation that exists outside the state. The purchases will not require 4-times the investment payback to the utilities. The purchases will be reduced each year until year 20, when energy efficiency has reduced the demand for electricity in the state to 100 units. RGGI sees this as a way to lower emissions, reduce energy demand, and save customers money. So far it is working in each of the three areas.

          It also serves to soak up the surplus of generation that has been built. More units are coming online while national electricity use has declined 2.1% last year.

          Virginia serves the shareholders while the RGGI states serve the customers while keeping the utilities healthy.

  10. TomH has the facts as to why nuclear today is not the obvious choice it once was (yes, in the 1950s cheap nuclear energy was going to save America!). But if it’s not the right choice for Dominion by such a margin today, why is it still on the table? Jim makes this point:

    “Virginians should ask themselves why electric utilities are shutting them down in states where they aren’t guaranteed a return on investment. Nuclear power often can’t compete in a deregulated market. . . . Would Dominion refurbish [its] units if the risks and costs of the projects weren’t being borne by the ratepayers? . . . The merchant generators are saying no.”

    THAT is the judgment of the marketplace. But if Dominion thinks it knows better than that, which is how people make money in markets — fine, re-license NA1 and NA2 (and there’s always NA3 license potentially) — but do so as “merchant plants” using Dominion Energy shareholder dollars for the investment, and then DE’s shareholders will get to keep most or all of the profits from these ventures (depending on whether DE reimbursed ratepayers up front for their existing investment in these units or left them “part-owners”).

    As TomH clearly points out, re-licensing has some positives, but many negatives. It would be a speculative gamble to go ahead with it in current circumstances, given the competitive alternatives. It is wrong to impose that economic gamble on ratepayers without the OK of their proxy, the VSCC, which will (if allowed to do its job) approach this from the same point of view: is this a ratepayer investment that makes sense given the alternatives?

    1. Rowinguy1 Avatar

      One factor that is driving nuclear out of the market is the currently very low cost of gas. Another factor driving some retirements, or threatened retirements, is the fact that New York and Illinois have enacted support mechanisms for zero emitting sources clearly intended to support continued nuclear operation of the giant fleet owned by Commonwealth Edison in Illinois and the New York nuclear units such as Indian Point, without which it would be much harder to supply NYC reliably or, I suspect, for NYS to meet its RGGI targets. First Energy Solutions has tried without success to get Ohio to prop up its units and is now, it seems to me, trying to get a nuke friendly DOE to find an “emergency” that would merit it receiving a similar stipend. Somewhat amusingly, one the plants they want to retire is the “Perry” plant on Lake Erie. And who is the Sec’y of DOE?

      1. Right on all points, Rowinguy1. If there were sufficient evidence that the current glut of natural gas would dissipate in only a few years it would be foolish to retire our nation’s nuclear generating fleet with the certain need to restore them looming! But the evidence for a gas bubble is not that clear; nuclear is being retired not mothballed; keeping it for another day is a gamble those with their own money at risk in merchant generation don’t seem willing to take.

        In the face of that market judgment, offset in only a couple of states by nuclear support payments, it’s hard not to be skeptical about DVP’s proposal to sink more billions into nuclear power — especially given DE’s apparent bias in favor of investing to the max in ratebased plant, yielding earnings stability, as opposed to investing in merchant plant leaving DVP to buy (arguably at lower cost) from third parties or the wholesale market.

  11. Peter Galuszka Avatar
    Peter Galuszka

    Rowinguy1 is right. The cost at Vogtle nuke in George is upwards of $25 billion. Westinghouse filed bankruptcy after losing $9 billon much related to SUmmer in South Carolina.
    I confused the two — sorry

    1. Peter,

      You were right in the sense that the estimate to complete the Summer plant was $25 billion (see my comment above). It was cancelled before that much was spent.

  12. LarrytheG Avatar

    re: islands and nukes and solar and diesel

    we’re talking about LARGE islands like Tasmania, many with millions of people. I think the North Anna plants serve less than a million.

    Most LARGE islands without native fossil fuels – so far – do not have nukes nor are they powered primarily by solar.

    Islands have no PJM to go buy power from. They are the perfect “laboratories” in deciding what fuels are affordable and practical to generate electricity.

    And so far.. for 99% of the world largest islands – the ones that do not have native fossil fuels – they use imported fossil fuels… namely fuel oil/diesel.

    SOME of them ARE starting to deploy solar but at night they either power by diesel or they shut down.

    The other thing to take note of also is that of all the places that could most directly benefit from demand-side conservation… is… these large islands.

    I think to a certain extent – when we talk about how power needs are to be met in Virginia – we keep falling back to PJM as the primary backup source – as if where that power actually comes from is not an issue – it just comes from PJM.

    Islands have no PJM and therefore are a better test of the truth of where electric power generation is – right now – and the two emerging technologies of solar and demand-side conservation – have yet to produce a single large island that has made the transition to …. essentially what we’ve been told that Germany and California are “trying” and failing at…

    Not recognizing this – sort of muddies the water when we talk about Dominion’s “plans”… retired fossil fuel plants, independent power producers, etc.

    Now.. I do not doubt for a New York Minute that the day WILL COME when we crack this nut… and enough solar is installed to power Va during the day and storage technology and demand-side conservation take care of a lot of the rest.

    I just don’t think we’re there yet… that we’re looking 10-30 years out…

    until we get there… do we want to power the night with fossil fuels or nukes?

    that’s the choice…. I just don’t see any others… or someone come back and explain how this perception of mine is wrong.

  13. No, you’re basically right. The problem with running an isolated grid on, say, an island, is you don’t have a lot of participants (either generation or load) to diversify the risk around. One big generator outage, one big weather event, and a lot changes quickly. Whereas, PJM covers thirteen relatively-densely-populated states and hundreds of generators and a wide diversity of climate simultaneously, it’s not easy to run a standalone grid even in a place the size of Puerto Rico, let alone on a smaller Caribbean island. Yes, the ability to time-shift electric power through batteries and other storage will open up new opportunities, but even with lots of batteries and more efficient buildings we are decades from eliminating the need for nighttime generation (and especially during extended winter storms), to carry all that electric heating demand on long winter nights (and, in summer, the nighttime air conditioning load). A kw saved by better energy efficiency is all gain, whereas a kw generated by solar and shifted to nighttime requires both the solar investment plus the battery investment.

  14. CleanAir&Water Avatar

    Jim, I like your new format … including our resident expert who favors change as a resource in the article. The differences in approach are clearer that way. I am blown away by Tom’s analysis of the benefits of efficiency, which I too have advocated for. Surry I and II can be replaced by the savings in demand that efficient buildings will create over the 14 year time span remaining for the Surry operations! Reducing demand with efficiency is a whole lot cheaper and cleaner than replacing the Surry output with new generation, fossil or not.

    Demand is not increasing. “Despite a growing economy, TVA now expects to sell 13 percent less power in 2027 than it did two decades earlier — the first sustained reversal in the growth of electricity usage in the 85-year history of TVA. The problem for our utilities is, as Tom has said repeatedly, “We need to give them (our utilities) a way to be financially healthy without charging us for projects that we don’t need.” That means changing the incentive structure that makes ’generating more’ the primary way to more profits today.

    This Yankee finds that Virginians seem to resist all manor of major change. Reversing the way our Bath hydro facility is used … to store excess solar power generated during the day and release it in the early evening … would be a viable option that Dominion has not put on the table. Sounds pretty obvious.

    “I agree absolutely that there comes a time when it is more efficient to start anew.” No nuclear units have been certified to operate past the 60 year time frame by the NRC. It sounds like no one yet knows the specifics, and therefore the cost, of qualifying for the extra 20 years. “As of February 2018, the NRC has renewed the operating licenses of 89 commercial nuclear reactors,” for the 60 year extension. For the new 80 year licensing the 2 units at Turkey Point are first in line, with Dominion’s 2 Surry units expected to file next, followed by Lake Anna.

    Operation and maintenance costs are the issues making nuclear units too expensive to continue competing. A Bloomberg analysis says more than half of the nuclear reactors in the U.S. are losing money. Then you have to throw in the costs of closing the plants. Jim Robo, CEO of NextEra Energy, predicted that by the early 2020s, it will be cheaper to build new renewables than to continue running existing coal and nuclear plants.

    Here are the costs Robo anticipates seeing “early in the next decade”:
    • Unsubsidized new wind: 2.0-2.5 cents per kilowatt-hour
    • Unsubsidized new solar: 3.0-4.0 cents per kilowatt-hour
    • Variable operating costs of existing coal or nuclear plants: 3.5-5.0 cents per kilowatt-hour

    Given what these facts and judgments show … starting over looks very positive. I think Dominion needs to stop charging us for development of Anna iii, and work with the Legislature and SCC to find a way to make ‘selling less’ OK. It looks like “it is time to start anew.”

    Two other unmentioned things … water to run the nukes and how fast offshore wind is now developing.

    GE has announced it is planning to focus on building offshore windmills. Now, with global demand for wind power growing, major oil and gas companies like Shell and Statoil are diversifying their portfolios by developing offshore wind, and the companies that provide services to offshore fossil fuel platforms are seeing a new market rising in their wake. Instrumental in building the Block Island wind farm, they possess “the skills and know-how to step into this business, which could see revenues of well over $20 billion in the next decade, ” according to Walt Musial of NREL

    Moody’s Investors Service in a new analysis of the sector:
    • New Jersey’s incoming governor has pledged 3.5 gigawatts by 2030.
    • New York’s governor has a goal of 2.4 gigawatts by 2030.
    • Massachusetts is calling for 1.6 gigawatts by 2027.

    Price has seen a 45% drop since Block Island. Why does VA still think offshore wind development is still decades down the road?

    Lastly, water use for both fossil fuels and nuclear resource and recovery, as well as generation, is a problem in many ways … the required quantity of water withdrawn and the amount that cannot be returned to the earth’s water cycle. Wind, solar and storage will conserve water as well.

  15. LarrytheG Avatar

    good … informative .. illuminating comments…

    we need to also recognize that “technology” is more than what we perceive right now.

    Let me give a quick example. Did anyone really appreciate the scope and scale of what has happened when a tiny emerging technology called cell phone began ? I do not ever recall anyone prior to that predicting the world we have today with respect to cell phones.

    similarly – there are two areas that exist right now but are not thought to have much effect… in the next 20-40s…

    1. smaller, safer nukes…that can modulate output…

    2. finding a cost effective way to “store” solar via hydrogen fuel that becomes the nightime power source.

    I’m sure there are others… and more often than not – how technology actually evolves defies all the prediction experts best guesses.

    but I still to think – where these evolving technologies will find their first real uses – is in the places that right now , still use diesel generators to produce electricity.

    Coal is done… just like whale oil went away but I’m not convinced that better Nukes are not possible… and I’m also not convinced that storage batteries like Tesla is using are actually truly cost effective – we’ll see… perhaps when produced in massive quantities they will be. If Tesla-like storage becomes cost effective – it completely changes the game with respect to the inflexibility of Nukes to modulate… they just put their excess into batteries to use later… right? We’re not there…

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