TODAY’S STUDY: The Numbers Behind The Diablo Canyon Shutdown
A Cost Effective and Reliable Zero Carbon Replacement Strategy for Diablo Canyon Power Plant
James H. Caldwell, V. John White, Liz Anthony, PhD, William Perea Marcus, JBS Energy, Inc, June 2016 (Center for Energy Efficiency and Renewable Technologies)
With the recent passage of SB 350, California has initiated the next phase in the deep decarbonization of its electric system. The result will be an increase in the renewable content of California’s electricity generation portfolio from 33+% in 2020 to 50+% in 2030 and a concomitant reduction in carbon emissions by some 40-45 MMTCO2 per year -- roughly half of current electric sector emissions. We now face another resource decision with large carbon emission implications – whether to extend the operating licenses for the Diablo Canyon nuclear power plant for twenty years. These licenses expire in 2024 (Unit 1) and 2025 (Unit 2).
The California Independent System Operator has stated: “The absence of the DCPP (Diablo Canyon) appears not to have negative impact on the reliability of the ISO transmission system with the assumption that there is sufficient deliverable generation within the ISO controlled grid.”1 That is, unlike Southern California Edison’s San Onofre Nuclear Generating Station (“SONGS”) retirement in 2012, DCPP’s location and continued operation is not critical to grid reliability as long as its energy and capacity is replaced. The location and composition of this replacement portfolio is not critical for grid reliability. Given that the process to plan, procure, and construct new generation to replace a retiring DCPP or to complete the license extension process at both the State and Federal level2 takes approximately seven years, the time to formally start the process for dealing with a potential DCPP retirement is at hand.
This study is intended to inform that process by comparing the cost to complete the license extension process plus the going forward operating, maintenance and incremental capital costs for DCPP operations from 2024 through 2045 (license extension period) to the cost of acquiring and operating a zero carbon replacement generation portfolio. The analysis will rely heavily on data submitted by Pacific Gas & Electric Company for its 2017 General Rate Case,3 and modeling work done for the Low Carbon Grid Study.4 The Low Carbon Grid Study is a peer reviewed comprehensive analysis of the California electric grid in 2030 where DCPP has been retired and replaced with a range of new renewable portfolios that both replace DCPP and meet California policy objectives of a grid that supports long term decarbonization with an interim 2030 target of 50+% RPS and 40+% reduction in carbon emissions below 1990 levels.
The Grid and Diablo Canyon
DCPP is easily the largest single generation asset on the California grid and the second largest in the entire West after the Palo Verde nuclear plant in Arizona. Over the past six years, it has provided 2240 MW of net capacity at a 90.0% capacity factor for an annual average energy production of 17,662 GWh/yr.
A major pillar of reliability requires that the electric grid be capable of withstanding the sudden loss of its largest single producing element without loss of load. This event is called an “N-1 contingency” and Federal, regional and State rules all require that this event be mitigated by holding so called “spinning reserve5” equal to or greater than its 2240 MW capacity any time that DCPP is operating. This quantity of spinning reserve is called the “MSSC” (Maximum System Single Contingency) in the CAISO tariff. Thus DCPP must have “one for one backup” for its energy and capacity at all times and this backup must be dedicated to reserve duty in case of an outage. Thus facilities supplying these spinning reserves are unavailable to perform other useful functions on the grid – such as flexibility to help shape net system load with deep penetrations of wind and solar generation.
When DCPP was constructed some 30 years ago, PG&E also built the Helms Pumped Storage Plant6 about 50 miles east of Fresno to be the cornerstone of the spinning reserve package for DCPP. Rated at 1212 MW of capacity, Helms is normally “self-scheduled” by PG&E to provide the bulk of the DCPP spin requirement.
The consequence of not being fully prepared for a trip of large nuclear facilities was graphically demonstrated in what is called the “Great Blackout of 2011”7 -- the largest power failure in California history. When Units 2 and 3 of the San Onofre Nuclear Generating Stations (“SONGS”) tripped off line during a grid disturbance that began in Arizona on the afternoon of September 8, 2011, almost seven million people were left without power for as much as twelve hours. Ensuring grid reliability in the event of loss of so much power in a single location is indeed serious business -- even if DCPP is not the original source of the problem.
The alternative to using Helms for spinning reserve is to start up and synchronize to the grid, but then leave “idling” some of the otherwise surplus natural gas plants in the state8. However, this alternative has several negative consequences that make using Helms to provide spin for DCPP the better solution. First, similar to an automobile in heavy city traffic vs. highway driving, the efficiency of most natural gas plants at idle or near idle is significantly less than when operated at full load.9 Thus natural gas is wasted and greenhouse gas (GHGs) emissions to maintain grid reliability are increased. Second, during light load hours in the fall, winter and spring, the energy produced at idle by the gas plants supplying spinning reserves for DCPP is not needed to serve load, and their presence crowds out other energy that is cheaper to produce and that emits less GHG – such as wind and/or solar. These zero carbon resources must then be “curtailed” to maintain the system load/resource balance10. Helms, whose replacement cost today is over $2B, was constructed specifically 30 years ago to save these costs.
Should DCPP retire, the next largest generation asset on the CAISO system is the Delta Energy Center in Pittsburg at 880 MW and the system spinning reserve requirement would then become the larger of 880 MW or 3% of the load on the system at that point in time. Thus, when DCPP retires, the system requirement for spinning reserve will be cut significantly, and at least a portion of Helms would then be available to supply system flexibility without restriction.
If the DCPP outage is unexpected, or planned for only a short duration, then PG&E would replace the lost energy with so called “system power” from other units somewhere in the West that have spare capacity. This system power, generally speaking, comes from otherwise surplus gas-fired generation with an average carbon emission rate of about 950 lb/MWh. So, if DCPP were to shut down for one year and the energy replaced with system power, CA electric sector carbon emissions would increase by roughly 7.6 million metric tons or about 8% of emissions today and about 38% of projected 2045 electric sector emissions if California meets its longterm carbon reduction goals. When DCPP finally retires, unless and until new carbon-free resources whose energy output equals the energy produced by DCPP are constructed, and those new resources are in addition to whatever resources are constructed for other reasons11 an increase in this system power output will be the result. This was the result when SONGS (which was only slightly smaller than DCPP) unexpectedly but permanently shut down in early 2012. CA electric sector carbon emissions increased by roughly 7 MMTCO2e in 2012 due to the SONGS shutdown.12
Replacing DCPP energy with only the very best, most efficient natural gas generation is little better. The most efficient natural gas plant operated in the most efficient manner (full load in cool weather at sea level) has a carbon emission rate of, at best, 800 lb/MWh, so the increased carbon emissions are “only” 6.4 million metric tons or 32% of the total long term emissions target.
Given the high cost of extending the NRC licenses, the high cost of continued operations at DCPP, and the risk of catastrophic failure of an aging plant on a seismically active site, the state of California needs to have a plan for retirement of DCPP. The plan must be to replace DCPP with zero GHG renewable energy and Energy Efficiency, both of which are incremental to existing policy initiatives and programs. As stated above, the time for that plan is now.
The alternate portfolios
The purpose of this study is to evaluate the feasibility of a cost-effective, reliable, zero GHG alternative to a license extension at DCPP. This requires a calculation of the cost of continuing to operate DCPP past its current license term vs. the cost of a replacement portfolio of capacity and energy to serve California electric load if and when DCPP retires. In order to do so, it is critical to understand the overall context of utility procurement over the next 10-30 years. There is no question that the dominant policy driver in this timeframe is the need to decarbonize the production of electricity to achieve critical climate policy goals. The decision to retire the plant or extend the DCPP license is an important decision but hardly constitutes the major procurement decision facing California. With the passage of SB 350, California utilities will be procuring 36-40 TWh of new bulk renewables (roughly 2 and one half times DCPP output) between now and 2030 to comply with the 50% Renewable Portfolio Standard (“RPS”). Plus, they will be acquiring all cost effective energy efficiency and accommodating a projected very significant expansion in customer sited and financed “rooftop solar” which does not count towards RPS compliance but clearly is a significant GHG reduction measure…
At the solar PV penetration levels envisioned in all scenarios of 50% or greater RPS, whether DCPP is operating or not, most studies, including the Low Carbon Grid Study, have found some new bulk storage facilities to be cost effective “mitigation measures.” These facilities operate on a daily cycle of charging during the middle of the day when the sun is shining and discharging in the early evening as the sun sets, shifting the “net load” curve to reduce over-generation and contribute to serving the evening load ramp without combusting natural gas.
For the purpose of this study, we assumed that this additional bulk storage would come from some fraction of the 5000 MW (six projects total) of new hydro pumped storage facilities under development in California that could be owned by PG&E. No attempt was made to specify which of these projects would/should be constructed. This decision, including provisions for an alternate advanced battery storage option, is best left to a robust competitive procurement process…
Somewhat by chance, all three alternate renewable portfolios have essentially the same capacity value at roughly 1750 MW of system Resource Adequacy (“RA”) value once the portfolios are adjusted for the capacity value of the added bulk storage. This compares favorably with the actual 1250 MW of capacity made available if the 2240 MW of RA capacity value of DCPP reduced by the 990 MW of additional spinning reserve required to operate DCPP. At today’s RA prices of roughly $40/kW-yr,19 this additional capacity is worth some $40M/yr if DCPP is retired. This capacity value was calculated by the existing CPUC protocols for calculating “System RA” adjusted for the likely revisions to wind and solar “Net Qualifying Capacity” based on new modeling that is ongoing in the CPUC Resource Adequacy proceeding.
Much like the discussion on storage above, this assumption should be revisited once the procurement process has refined the portfolio options more definitively.
To assess the transmission requirements of the alternate portfolios, we used the results of the Low Carbon Grid Study for the Diverse and High Solar portfolios. These portfolios were deliberately picked to utilize as much existing and previously planned transmission expansion as practical. Only the load ratio share20 of the major new tie line for Wyoming wind needs to be assessed against these portfolios for cost comparison purposes. All other planned transmission expansions, such as the West of Devers and Gates/Gregg projects in California, are designed to reach a 50% RPS whether DCPP continues to operate or not.
The Valley Solar portfolio is a different story. Constructing 6,500 MW of new solar generation in the Central Valley will clearly require significant new transmission investment even after allocating the transmission now used by DCPP to the new portfolio…
The strong conclusion from the foregoing analysis is that it is clearly in the interest of California ratepayers to replace DCPP with a renewable portfolio in an orderly transition on a timetable that will enable ratepayers to benefit from the renewable tax credits that may expire in 2020. These renewable resources will be additive to the recently adopted policy of a 50% RPS by 2030. It is also in ratepayer interests to overhaul and expand current energy efficiency programs to bear part of the load caused by retirement of DCPP.
We can confidently state that on a life cycle basis the investment in renewables and efficiency will, over time, provide consumers with lower cost electricity than DCPP, will be more reliable, and will eliminate the real financial and safety risks inherent in operating nuclear reactors that are 40 to 60 years old.
Our conclusion is based on our analysis that: (a) the base, conventional wisdom estimate of DCPP license extension period costs at more than $14B is roughly the same as the base, conventional wisdom procurement and operating costs of a robust range of renewable resources and incremental energy efficiency that embody the true meaning of “least cost/best fit.”; (b) there is a near certainty that the base costs for DCPP life extension are low by at least 10% and probably more to cover either unforeseen issues during the license extension period, or conditions attached to the license extension to deal with issues such as seismic retrofits and/or once through cooling mitigation measures; the need to close unit 1 by 2023 due to embrittlement; the need for new steam generators, etc., (c) there is strong evidence to believe that the renewable replacement portfolio can be procured for at least 10% less than the base estimate; (d) that the retirement of DCPP will reduce required spinning reserves and relieve the Helms pumped storage plant, which is worth in excess of $2B, for a higher duty of providing flexibility to the grid to accommodate ever increasing penetrations of zero variable cost, zero carbon emitting renewable resources onto California’s electric grid.
In addition, the DCPP costs are uncertain and subject to inflation. The renewable alternative costs are largely fixed. They have no fuel costs and little maintenance exposure. They are low risk inflation hedges and they eliminate the awesome enterprise level risks inherent in running nuclear reactors in a seimically active region.