Tag Archives: nuclear power

Do small modular reactors (SMR) hold real promise?

The economic analyses of the projected costs for small modular reactors (SMRs) appear to rely on two important assumptions: 1) that the plants will run at capacity factors of current nuclear plants (i.e., 70%-90%+) and 2) that enough will be built quickly enough to gain from “learning by doing” on scale as has occurred with solar, wind and battery technologies. The problem with these assumptions is that they require that SMRs crowd out other renewables with little impact on gas-fired generation.

To achieve low costs in nuclear power requires high capacity factors, that is the total electricity output relative to potential output. The Breakthrough Institute study, for example, assumes a capacity factor greater than 80% for SMRs. The problem is that the typical system load factor, that is the average load divided by the peak load, ranges from 50% to 60%. A generation capacity factor of 80% means that the plant is producing 20% more electricity than the system needs. It also means that other generation sources such as solar and wind will be pushed aside by this amount in the grid. Because the SMRs cannot ramp up and down to the same degree as load swings, not only daily but also seasonally, the system will still need load following fossil-fuel plants or storage. It is just the flip side of filling in for the intermittency of renewables.

To truly operate within the generation system in a manner that directly displaces fossil fuels, an SMR will have to operate at a 60% capacity factor or less. Accommodating renewables will lower that capacity factor further. Decreasing the capacity factor from 80% to 60% will increase the cost of an SMR by a third. This would increase the projected cost in the Breakthrough Institute report for 2050 from $41 per megawatt-hour to $55 per megawatt-hour. Renewables with storage are already beating this cost in 2022 and we don’t need to wait 30 years.

And the Breakthrough Institute study relies questionable assumptions about learning by doing in the industry. First, it assumes that conventional nuclear will experience a 5% learning benefit (i.e., costs will drop 5% for each doubling of capacity). In fact, the industry shows a negative learning rate--costs per kilowatt have been rising as more capacity is built. It is not clear how the SMR industry will reverse this trait. Second, the learning by doing effect in this industry is likely to be on a per plant rather than per megawatt or per turbine basis as has been the case with solar and turbines. The very small unit size for solar and turbine allows for off site factory production with highly repetitive assembly, whereas SMRs will require substantial on-site fabrication that will be site specific. SMR learning rates are more likely to follow those for building construction than other new energy technologies.

Finally, the report does not discuss the risk of catastrophic accidents. The probability of a significant accident is about 1 per 3,700 reactor operating years. Widespread deployment of SMRs will vastly increase the annual risk because that probability is independent of plant size. Building 1,000 SMRs could increase the risk to such a level that these accidents could be happening once every four years.

The Fukushima nuclear plant catastrophe is estimated to have cost $300 billion to $700 billion. The next one could cost in excess of $1 trillion. This risk adds a cost of $11 to $27 per megawatt-hours.

Adding these risk costs on top of the adjusted capacity factor, the cost ranges rises to $65 to $82 per megawatt-hour.

Close Diablo Canyon? More distributed solar instead

More calls for keeping Diablo Canyon have coming out in the last month, along with a proposal to match the project with a desalination project that would deliver water to somewhere. (And there has been pushback from opponents.) There are better solutions, as I have written about previously. Unfortunately, those who are now raising this issue missed the details and nuances of the debate in 2016 when the decision was made, and they are not well informed about Diablo’s situation.

One important fact is that it is not clear whether continued operation of Diablo is safe. Unit No. 1 has one of the most embrittled containment vessels in the U.S. that is at risk during a sudden shutdown event.

Another is that the decision would require overriding a State Water Resources Control Board decision that required ending the use of once-through cooling with ocean water. That cost was what led to the closure decision, which was 10 cents per kilowatt-hour at current operational levels and in excess of 12 cents in more likely operations.

So what could the state do fairly quickly for 12 cents per kWh instead? Install distributed energy resources focused on commercial and community-scale solar. These projects cost between 6 and 9 cents per kWh and avoid transmission costs of about 4 cents per kWh. They also can be paired with electric vehicles to store electricity and fuel the replacement of gasoline cars. Microgrids can mitigate wildfire risk more cost effectively than undergrounding, so we can save another $40 billion there too. Most importantly they can be built in a matter of months, much more quickly than grid-scale projects.

As for the proposal to build a desalination plant, pairing one with Diablo would both be overkill and a logistical puzzle. The Carlsbad plant produces 56,000 acre-feet annually for San Diego County Water Agency. The Central Coast where Diablo is located has a State Water Project allocation of 45,000 acre-feet which is not even used fully now. That plant uses 35 MW or 1.6% of Diablo’s output. A plant built to use all of Diablo’s output could produce 3.5 million acre-feet, but the State Water Project would need to be significantly modified to move the water either back to the Central Valley or beyond Santa Barbara to Ventura. All of that adds up to a large cost on top of what is already a costly source of water of $2,500 to $2,800 per acre-foot.

What to do about Diablo Canyon?

The debate over whether to close Diablo Canyon has resurfaced. The California Public Utilities Commission, which support from the Legislature, decided in 2018 to close Diablo by 2025 rather than proceed to relicensing. PG&E applied in 2016 to retire the plant rather than relicense due to the high costs that would make the energy uneconomic. (I advised the Joint CCAs in this proceeding.)

Now a new study from MIT and Stanford finds potential savings and emission reductions from continuing operation. (MIT in particular has been an advocate for greater use of nuclear power.) Others have written opinion articles on either side of the issue. I wrote the article below in the Davis Enterprise addressing this issue. (It was limited to 900 words so I couldn’t cover everything.)

IT’S OK TO CLOSE DIABLO CANYON NUCLEAR PLANT
A previous column (by John Mott-Smith) asked whether shutting down the Diablo Canyon nuclear plant is risky business if we don’t know what will replace the electricity it produces. John’s friend Richard McCann offered to answer his question. This is a guest column, written by Richard, a universally respected expert on energy, water and environmental economics.

John Mott-Smith asked several questions about the future of nuclear power and the upcoming closure of PG&E’s Diablo Canyon Power Plant in 2025. His main question is how are we going to produce enough reliable power for our economy’s shift to electricity for cars and heating. The answers are apparent, but they have been hidden for a variety of reasons.
I’ve worked on electricity and transportation issues for more than three decades. I began my career evaluating whether to close Sacramento Municipal Utility District’s Rancho Seco Nuclear Generating Station and recently assessed the cost to relicense and continue operations of Diablo after 2025.
Looking first at Diablo Canyon, the question turns almost entirely on economics and cost. When the San Onofre Nuclear Generating Station closed suddenly in 2012, greenhouse gas emissions rose statewide the next year, but then continued a steady downward trend. We will again have time to replace Diablo with renewables.
Some groups focus on the risk of radiation contamination, but that was not a consideration for Diablo’s closure. Instead, it was the cost of compliance with water quality regulations. The power plant currently uses ocean water for cooling. State regulations required changing to a less impactful method that would have cost several billion dollars to install and would have increased operating costs. PG&E’s application to retire the plant showed the costs going forward would be at least 10 to 12 cents per kilowatt-hour.
In contrast, solar and wind power can be purchased for 2 to 10 cents per kilowatt-hour depending on configuration and power transmission. Even if new power transmission costs 4 cents per kilowatt-hour and energy storage adds another 3 cents, solar and wind units cost about 3 cents, which totals at the low end of the cost for Diablo Canyon.
What’s even more exciting is the potential for “distributed” energy resources, where generation and power management occurs locally, even right on the customers’ premises rather than centrally at a power plant. Rooftop solar panels are just one example—we may be able to store renewable power practically for free in our cars and trucks.
Automobiles are parked 95% of the time, which means that an electric vehicle (EV) could store solar power at home or work during the day and for use at night. When we get to a vehicle fleet that is 100% EVs, we will have more than 30 times the power capacity that we need today. This means that any individual car likely will only have to use 10% of its battery capacity to power a house, leaving plenty for driving the next day.
With these opportunities, rooftop and community power projects cost 6 to 10 cents per kilowatt-hour compared with Diablo’s future costs of 10 to 12 cents.
Distributed resources add an important local protection as well. These resources can improve reliability and resilience in the face of increasing hazards created by climate change. Disruptions in the distribution wires are the cause of more than 95% of customer outages. With local generation, storage, and demand management, many of those outages can be avoided, and electricity generated in our own neighborhoods can power our houses during extreme events. The ad that ran during the Olympics for Ford’s F-150 Lightning pick-up illustrates this potential.
Opposition to this new paradigm comes mainly from those with strong economic interests in maintaining the status quo reliance on large centrally located generation. Those interests are the existing utilities, owners, and builders of those large plants plus the utility labor unions. Unfortunately, their policy choices to-date have led to extremely high rates and necessitate even higher rates in the future. PG&E is proposing to increase its rates by another third by 2024 and plans more down the line. PG&E’s past mistakes, including Diablo Canyon, are shown in the “PCIA” exit fee that [CCA] customers pay—it is currently 20% of the rate. Yolo County created VCEA to think and manage differently than PG&E.
There may be room for nuclear generation in the future, but the industry has a poor record. While the cost per kilowatt-hour has gone down for almost all technologies, even fossil-fueled combustion turbines, that is not true for nuclear energy. Several large engineering firms have gone bankrupt due to cost overruns. The global average cost has risen to over 10 cents per kilowatt-hour. Small modular reactors (SMR) may solve this problem, but we have been promised these are just around the corner for two decades now. No SMR is in operation yet.
Another problem is management of radioactive waste disposal and storage over the course of decades, or even millennia. Further, reactors fail on a periodic basis and the cleanup costs are enormous. The Fukuyama accident cost Japan $300 to $750 billion. No other energy technology presents such a degree of catastrophic failure. This liability needs to be addressed head on and not ignored or dismissed if the technology is to be pursued.

Should CCAs accept a slice of Diablo Canyon power?

The northern California community choice aggregators (CCAs) are considering a offer from PG&E to allocate to each CCA a proportionate share of parts of its portfolio, including the Diablo Canyon nuclear generation station. Many CCA boards are hearing from anti-nuclear activists to deny this offer, both for moral reasons and the belief that such a rejection will somehow pressure PG&E financially. The first set of concern is beyond my professional expertise, but their reasoning on the economic and regulatory issues is incorrect.

  • CCAs buy a substantial portion of their generation (the majority for many of them) from the California Independent System Operator (CAISO) energy markets. PG&E schedules Diablo Canyon into those CAISO markets and under the current CAISO tariffs, nuclear generation is a “must take” resource that the CAISO can’t turn back. So the entire output of Diablo Canyon is scheduled into the CAISO market (without any bidding process), PG&E is paid the market clearing price (MCP) for that Diablo power, and the CCAs buy that mix of nuclear power at the MCP. There is no discretion for either the CAISO or the CCAs in taking excess power from Diablo. There is no “lifeline” for Diablo that the CCAs have any control over under current legal and regulatory parameters.
  • CCAs already pay for a proportionate share of Diablo Canyon equal to the CCAs share of overall load. That payment is broken into two parts (and maybe a third): 1) the purchase of energy from the CAISO at the MCP and 2) the stranded capital and operating costs above the MCP in the PCIA. (CCAs also may be paying for a share of the resource adequacy, but I haven’t thought through that one.) Thus, if the CCAs receive credit for the energy that they are already paying for, the energy portion essentially comes as “free”. In addition, because CCAs currently pay for the remaining share of Diablo costs, but get no energy credit for that in the PCIA calculation, then that credit is in the PCIA is also “free”. In addition, the CCAs gain credit for Diablo’s GHG-free generation (as recognized in the Air Resources Board GHG allowance program) as LSE’s for no extra cost, or for “free.” The bottom line is when the CCAs gain credit for products that they are already paying for, receipt of those products is for “free.”
  • Accepting this deal will not solve ALL of the CCAs problems, but that’s a false goal. That was never the intent. It does however give the CCAs a respite to get through the period until Diablo retires. One needs to recognize that this provides some of the needed relief.
  • Finally, there’s never any certainty over any large deal. Uncertainty should not freeze decision making. The uncertainty about the PCIA going forward is equally large and perhaps offsetting. The risks should be identified, discussed, considered and addressed to the extent possible. But that’s different than simply nixing the deal without addressing the other large risk. Naively believing that Diablo can be closed in short order (especially with the COVID crisis) is not a true risk management strategy.

From these points, we can come to these conclusions:

  1. Whether the CCAs accept or reject the nuclear offer has NO impact on PG&E’s revenue stream. The decisions that the CCAs face are entirely about whether the CCAs can lower their costs and gain some additional GHG reduction credits that they are already paying for (in other words, reduce their subsidies of bundled customers.) Nothing that the CCAs decide will affect the closure date of Diablo. If the CCAs reject the allocations, it will simply be business as usual to the full closures in 2025. Any other interpretation doesn’t reflect the current regulatory environment at the CPUC which are unlikely to change (and even that is unknown) until enough commissioners’ five-year terms roll over.
  2. The system can only be changed by legislative and regulatory action. That means that the CCAs must make the most prudent financial decisions within the current context rather than making a purely symbolic gesture that is financially adverse and will do nothing to change the BAU practice. A wise decision would consider what is the true impact of the action on
  3. Finally, early closure of Diablo will NOT remove the invested capital cost from PG&E’s ratebase, which is what drives the PCIA. After the plant is closed, activists will ALSO have to show that the INVESTMENT in the plant was imprudent and should not have been allowed. Given the long history on decisions and settlements in Diablo investment costs and the inclusion of recovery of Diablo costs in both AB1890 and AB1X at the beginning and end of the energy crisis, that is an impossible task. Only a constitutional amendment through the initiative process could possibly lead to such an action, and even that would have to survive a court challenge that probably would push past 2024.

I want to finish with what I think is a very important point that has been overlooked by the activists: The effort to close Diablo Canyon has won. Activists might not like the timeline of that victory, but it is a victory nevertheless that looked unachievable prior to 2016. It’s worthwhile considering whether the added effort for what will be for a variety of reasons little gain is an important question to answer.

Note that Diablo Canyon is already scheduled for closure in 2024 and 2025. A proceeding to either reopen A.16-08-006 or to open a new rulemaking or application would probably take close to a year, so the proceeding probably wouldn’t open until almost 2021. The actual proceeding would take up to a year, so now we’re to 2022 before an actual decision. PG&E would have to take up to a year to plan the closure at that point, which then takes us to 2023. So at best the plant closes a year earlier than currently scheduled. In addition, PG&E still receives the full payments for its investments and there’s likely no capital additions avoided by the early closure, so the cost savings would be minimal.

We’ve already paid for Diablo Canyon

As I wrote last week, PG&E is proposing that a share of Diablo Canyon nuclear plant output be allocated to community choice aggregators (CCAs) as part of the resolution of issues related to the Integrated Resource Plan (IRP), Resource Adequacy (RA) and Power Charge Indifference Adjustment (PCIA) rulemakings. While the allocation makes sense for CCAs, it does not solve the problem that PG&E ratepayers are paying for Diablo Canyon twice.

In reviewing the second proposed settlement on PG&E costs in 1994, we took a detailed look at PG&E’s costs and revenues at Diablo. Our analysis revealed a shocking finding.

Diablo Canyon was infamous for increasing in cost by more than ten-fold from the initial investment to coming on line. PG&E and ratepayer groups fought over whether to allow $2.3 billion dollars.  The compromise in 1988 was to essentially shift the risk of cost recovery from ratepayers to PG&E through a power purchase agreement modeled on the Interim Standard Offer Number 4 contract offered to qualifying facilities (but suspended as oversubscribed in 1985).

However, the contract terms were so favorable and rich to PG&E, that Diablo costs negatively impacted overall retail rates. These costs were a key contributing factor that caused industrial customers to push for deregulation and restructuring. As an interim solution in 1995 in anticipation of forthcoming restructuring, PG&E and ratepayer groups arrived at a new settlement that moved Diablo Canyon back into PG&E’s regulated ratebase, earning the utilities allowed return on capital. PG&E was allowed to keep 100% of profit collected between 1988 and 1995. The subsequent 1996 settlement made some adjustments but arrived at essentially the same result. (See Decision 97-05-088.)

While PG&E had borne the risks for seven years, that was during the plant startup and its earliest years of operation.  As we’ve seen with San Onofre NGS and other nuclear plants, operational reliability is most at risk late in the life of the plant. PG&E’s originally took on the risk of recovering its entire investment over the entire life of the plant.  The 1995 settlement transferred the risk for recovering costs over the remaining life of the plant back to ratepayers. In addition, PG&E was allowed to roll into rate base the disputed $2.3 billion. This shifted cost recovery back to the standard rate of depreciation over the 40 year life of the NRC license. In other words, PG&E had done an end-run on the original 1988 settlement AND got to keep the excess profits.

The fact that PG&E accelerated its investment recovery over the first seven years and then shifted recovery risk to ratepayers implies that PG&E should be allowed to recover only the amount that it would have earned at a regulated return under the original 1988 settlement. This is equal to the discounted net present value of the net income earned by Diablo Canyon, over both the periods of the 1988 (PPA) and 1995 settlements.

In 1996, we calculated what PG&E should be allowed to recover in the settlement given this premise.  We assumed that PG&E would be allowed to recover the disputed $2.3 billion because it had taken on that risk in 1988, but the net income stream should be discounted at the historic allowed rate of return over the seven year period.  Based on these assumptions, PG&E had recovered its entire $7.7 billion investment by October 1997, just prior to the opening of the restructured market in March 1998.  In other words, PG&E shareholders were already made whole by 1998 as the cost recovery for Diablo was shifted back to ratepayers.  Instead the settlement agreement has caused ratepayers to pay twice for Diablo Canyon.

PG&E has made annual capital additions to continue operation at Diablo Canyon since then and a regulated return is allowed under the regulatory compact.  Nevertheless, the correct method for analyzing the potential loss to PG&E shareholders from closing Diablo is to first subtract $5.1 billion from the plant in service, reducing the current ratebase to capital additions incurred since 1998. This would reduces the sunk costs that are to be recovered in rates from $31 to $3 per megawatt-hour.

Note that PG&E shareholders and bondholders have earned a weighted return of approximately 10% annually on this $5.1 billion since 1998. The compounded present value of that excess return was $18.1 billion by 2014 earned by PG&E.

Calculating the risk reduction benefits of closing Germany’s nuclear plants

Max Aufhammer at the Energy Institute at Haas posted a discussion of this recent paper reviewing the benefits and costs of the closure of much of the German nuclear fleet after the Fukushima accident in 2011.

Quickly reading the paper, I don’t see how the risk of a nuclear accident is computed, but it looks like the value per MWH was taken from a different paper. So I did a quick back of the envelope calculation for the benefit of the avoided consequences of an accident. This paper estimates a risk of an accident once every 3,704 reactor-operating years (which is very close to a calculation I made a few years ago). (There are other estimates showing significant risk as well.) For 10 German reactors, this translates to 0.27% per year.

However, this is not a one-off risk, but rather a cumulative risk over time, as noted in the referenced study. This is akin to the seismic risk on the Hayward Fault that threatens the Delta levees, and is estimated at 62% over the next 30 years. For the the German plants, this cumulative probability over 30 years is 8.4%. Using the Fukushima damages noted in the paper, this represents $25 to $63 billion. Assuming an average annual output of 7,884 GWH, the benefit from risk reduction ranges from $11 to $27 per MWH.

The paper appears to make a further error in using only the short-run nuclear fuel costs of $10 per MWH as representing the avoided costs created by closing the plants. Additional avoided costs include avoided capital additions that accrue with refueling and plant labor and O&M costs. For Diablo Canyon, I calculated in PG&E’s 2019 ERRA proceeding that these costs were close to an additional $20 per MWH. I don’t know the values for the German plants, but clearly they should be significant.

CCAs don’t undermine their mission by taking a share of Diablo Canyon

Northern California community choice aggregators (CCAs) are considering whether to accept an offer from PG&E to allocate a proportionate share of its “large carbon-free” generation as a credit against the power charge indifference adjustment (PCIA) exit fee.  The allocation would include a share of Diablo Canyon power. The allocation for 2019 and 2020; an extension of this allocation is being discussed on the PCIA rulemaking.

The proposal faces opposition from anti-nuclear and local community activists who point to the policy adopted by many CCAs not to accept any nuclear power in their portfolios. However, this opposition is misguided for several reasons, some of which are discussed in this East Bay Community Energy staff report.

  • The CCAs already receive and pay for nuclear generation as part of the mix of “unspecified” power that the CCAs buy through the California Independent System Operator (CAISO). The entire cost of Diablo Canyon is included in the Total Portfolio Cost used to calculate the PCIA. The CCAs receive a “market value” credit against this generation, but the excess cost of recovering the investment in Diablo Canyon (for which PG&E is receiving double payment based on calculations I made in 1996) is recovered through the PCIA. The CCAs can either continue to pay for Diablo through the PCIA without receiving any direct benefits, or they can at least gain some benefits and potentially lower their overall costs. (CCAs need to be looking at their TOTAL generation costs, not just their individual portfolio, when resource planning.)
  • Diablo Canyon is already scheduled to close Unit 1 in 2024 and Unit 2 in 2025 after a contentious proceeding. This allocation is unlikely to change this decision as PG&E has said that the relicensed plant would cost in excess of $100 per megawatt-hour, well in excess of its going market value. I have written extensively here about how costly nuclear power has been and has yet to show that it can reduce those costs. Unless the situation changes significantly, Diablo Canyon will close then.
  • Given that Diablo is already scheduled for closure, the California Public Utilities Commission (CPUC) is unlikely to revisit this decision. But even so, a decision to either reopen A.16-08-006 or to open a new rulemaking or application would probably take close to a year, so the proceeding probably would not open until almost 2021. The actual proceeding would take up to a year, so now we are to 2022 before an actual decision. PG&E would have to take up to a year to plan the closure at that point, which then takes us to 2023. So at best the plant closes a year earlier than currently scheduled. In addition, PG&E still receives the full payments for its investments and there is likely no capital additions avoided by the early closure, so the cost savings would be minimal.

Nuclear vs. storage: which is in our future?

Two articles with contrasting views of the future showed up in Utility Dive this week. The first was an opinion piece by an MIT professor referencing a study he coauthored comparing the costs of an electricity network where renewables supply more than 40% of generation compared to using advanced nuclear power. However, the report’s analysis relied on two key assumptions:

  1. Current battery storage costs are about $300/kW-hr and will remain static into the future.
  2. Current nuclear technology costs about $76 per MWh and advanced nuclear technology can achieve costs of $50 per MWh.

The second article immediately refuted the first assumption in the MIT study. A report from BloombergNEF found that average battery storage prices fell to $156/kW-hr in 2019, and projected further decreases to $100/kW-hr by 2024.

The reason that this price drop is so important is that, as the MIT study pointed out, renewables will be producing excess power at certain times and underproducing during other peak periods. MIT assumes that system operators will have to curtail renewable generation during low load periods and run gas plants to fill in at the peaks. (MIT pointed to California curtailing about 190 GWh in April. However, that added only 0.1% to the CAISO’s total generation cost.) But if storage is so cheap, along with inexpensive solar and wind, additional renewable capacity can be built to store power for the early evening peaks. This could enable us to free ourselves from having to plan for system peak periods and focus largely on energy production.

MIT’s second assumption is not validated by recent experience. As I posted earlier, the about to be completed Vogtle nuclear plant will cost ratepayers in Georgia and South Carolina about $100 per MWh–more than 30% more than the assumption used by MIT. PG&E withdrew its relicensing request for Diablo Canyon because the utility projected the cost to be $100 to $120 per MWh. Another recent study found nuclear costs worldwide exceeded $100/MWh and it takes an average of a decade finish a plant.

Another group at MIT issued a report earlier intended to revive interest in using nuclear power. I’m not sure of why MIT is so focused on this issue and continuing to rely on data and projections that are clearly outdated or wrong, but it does have one of the leading departments in nuclear science and engineering. It’s sad to see that such a prestigious institution is allowing its economic self interest to cloud its vision of the future.

What do you see in the future of relying on renewables? Is it economically feasible to build excess renewable capacity that can supply enough storage to run the system the rest of the day? How would the costs of this system compare to nuclear power at actual current costs? Will advanced nuclear power drop costs by 50%? Let us know your thoughts and add any useful references.

The two problems to be addressed head on by nuclear power advocates

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Nuclear power advocates bring up the technology as a supposedly necessary part of a zero-GHG portfolio to address climate change. They insist that the “next generation” technology will be a winner if it is allowed to be developed.

Nevertheless, nuclear has two significant problems beyond whatever is in the next generation technology:

  1. Construction cost overruns are the single biggest liability that has been killing the technology. While most large engineering projects have contingencies for 25-30% overruns, almost all nuclear plants have overruns that are multiples of the original cost estimates. This has been driving the most experienced engineering/construction firms into bankruptcies. Until that problem is resolved, all energy providers should be very leery of making commitments to a technology that takes at least 7 years to build.
  2. We still haven’t addressed waste disposal and storage over the course of decades, much less millennia. No other energy technology presents such a degree of catastrophic failure from a single source. Again, this liability needs to be addressed head on and not ignored or dismissed if the technology is to be pursued.