Tag Archives: hydropower

PG&E already has $300 million to contribute to removing Potter Valley

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PG&E announced that it projects the cost of decommissioning the Scott and Van Horn Dams in the Potter Valley Project will cost $532 million. However, by 2029 PG&E will have already collected from ratepayers $321 million towards that cost in depreciation expenses.

PG&E makes capital investments in generation, transmission and distribution equipment, and then recovers those investments on an annual basis akin to a mortgage payment. The annual cost recovery rate is computed as a sum of the cost of capital, defined as shareholder return and debt interest rate, plus the depreciation expense which is calculated based on the expected life of the equipment.

Depreciation has two parts. The first goes towards recovery of the initial cost of construction. This is on top of the authorized rate of return that covers debt interest and shareholders return on equity. The second is the salvage value which is the expected value of the remaining components at the end of the life of the asset. Except in the case of dams, that salvage value is negative due to the cost of decommissioning.

PG&E is collecting these depreciation expenses including decommissioning costs for its entire fleet of hydropower projects. In effect, PG&E has created an insurance fund for its full portfolio of projects and the cost of any single decommissioning comes from this portfolio insurance fund. While PG&E placed a 25% probability that Potter Valley would be decommissioned, it calculated a portfolio-wide probability of decommissioning at 22%. Many of these projects will not be decommissioned for at least another half century as they were recently relicensed and probably even longer given the value of these assets for power production. Those unexpended decommissioning funds collected for projects likely to operate for the foreseeable future (e.g., the Feather River Project) are intended to be spent on actual projects such as Potter Valley rather than just to continue to accrue income for shareholders and creditors.

As part of its triennial General Rate Case (GRC) application, PG&E estimated the costs to decommission hydropower facilities as part of depreciation studies used to compute capital cost recovery rates. In Chapter 8 of its GRC filing in Application 18-12-009, filed December 2018,[1] PG&E reported the estimated 2022 decommissioning cost for Potter Valley at $196.3 million. PG&E estimated the total decommissioning costs for the projects included in their list of hydropower projects was $830.0 million.

Based on PG&E’s collection of $196 million by 2022 towards Potter Valley’s decommissioning and the authorized rate of return on investment of 7.27%, PG&E will have $321 million already banked in 2029 to commit to the decommissioning. This leaves $211 million or 40% of PG&E’s projected cost to be paid in addition from other sources, including ratepayers.

As an aside, PG&E’s cost estimate is in line with initial estimates our project team made for the Two Basin Solution coalition in 2020. We also found that each of the options cost approximately the same, similar to the results another team I worked on projected in 2006 for decommissioning the Klamath Project.

[1] PG&E, “Hydro Decommissioning WPS Exhibit 5 Chapter 8.pdf”, A.18-12-009, December 2018.

California’s perceived “solar glut” problem is actually a “nuclear glut” problem

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Several news stories have asserted that California has a “glut” of solar power that is being wasted and sold at a loss to other states. The problem is that the stories mischaracterize the situation, both in cause and magnitude.

The Diablo Canyon nuclear power units were scheduled to be retired in 2024 and 2025 due to having reached the end of their license and concerns around public safety from the aging plant. As a result, state energy regulators launched an aggressive renewable energy and battery storage procurement process in 2018 following the decision to close Diablo Canyon. Those added resources are now coming online to offset the anticipated loss of energy output from Diablo Canyon’s closure.

However, despite those additional renewable resources, the state legislature and Governor Newsom then extended the life of Diablo Canyon in 2022 to 2030. Diablo Canyon’s 2,200 megawatts of around-the-clock energy production – which adds up to 18 million megawatt hours a year – is the true source of grid management issues, particularly during the spring when the majority of energy curtailments occur.

This imbalance is exacerbated by the large swings in the state’s hydropower production, from 17 million megawatt hours during a dry 2022 to 30 million megawatt hours in a wet 2023. These swings are inherent in California’s power system, and related curtailments were common for decades before solar was on the scene. In other words, California will always need to have excess energy in wet years if it wants sufficient power in the other two-thirds of the years that are average or dry. Diablo Canyon’s year-round, around the clock output only makes that glut worse.

Not only is Diablo Canyon’s extension clogging up transmission lines and driving curtailment, it is also a high cost energy resource. PG&E initially claimed the Diablo Canyon power would cost about 5.5 cent per kilowatt hour, which is near the average cost of the California Independent System Operator’s (CAISO) energy purchases. Instead, PG&E is asking the California Public Utilities Commission to charge more than 9 cents per kilowatt hour, nearly double the cost of the average energy purchase.

Instead of blaming and halting California’s clean energy progress, an easier solution that would solve most of the curtailment issue would be to shut down Diablo Canyon from March to May, when energy demand is lowest in the state. This is when loads are lowest and hydro output the highest. Reducing at least some of Diablo Canyon’s 18 million megawatt hours per year, would more than offset the 3.2 million megawatt hours of solar energy that were curtailed in 2024. Diablo Canyon would still be available to meet summertime peaks. That would save ratepayers money and reduce the need to sell excess generation at a loss. 

California is already addressing other causes of curtailments by installing more storage capacity. It would be foolish to reduce solar generation now when we will need it in the near future to match the additional storage capacity. 

Decommissioning Klamath River dams comes to fruition

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In 2006, M.Cubed prepared a report for the California Energy Commission that showed PacifiCorp, owner of the four dams on the Klamath River, would be financially indifferent between decommissioning or relicensing the projects with the Federal Energy Regulatory Commission. That conclusion has since been reinforced by a 75% decline in replacement renewable power costs since then. That study opened the door for all parties to negotiate an agreement in 2010 to move forward with decommissioning.

In 2015, I wrote here about how that agreement was in peril. I tracked the progress of the situation in the comments in that post.

Fortunately, those hurdles were overcome and the decommissioning began this year in 2023. Copco 2 has now been completely removed and the project is moving on to the next dam.

After all four dams are taken we can see how successful this approach might be in restoring rivers on the West Coast.

This is the initial report on the economics of decommissioning versus relicense conducted for the California Energy Commission.

How to choose a water system model

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The California Water & Environmental Modeling Forum (CWEMF) has proposed to update its water modeling protocol guidance, last issued in 2000. This modeling protocol applies to many other settings, including electricity production and planning (which I am familiar with). I led the review of electricity system simulation models for the California Energy Commission, and asked many of these questions then.

Questions that should be addressed in water system modeling include:

  • Models can be used for either short-term operational or long term planning purposes—models rarely can serve both masters. The model should be chosen for its analytic focus is on predicting with accuracy and/or precision a particular outcome (usually for short term operations) or identifying resilience and sustainability.
  • There can be a trade off between accuracy and precision. And focusing overly so on precision in one aspect of a model is unlikely to improve the overall accuracy of the model due to the lack of precision elsewhere. In addition, increased precision also increases processing time, thus slowing output and flexibility.
  • A model should be able to produce multiple outcomes quickly as a “scenario generator” for analyzing uncertainty, risk and vulnerability. The model should be tested for accuracy when relaxing key constraints that increase processing time. For example, in an electricity production model, relaxing the unit commitment algorithm increased processing speed twelve fold while losing only 7 percent in accuracy, mostly in the extreme tail cases.
  • Water models should be able to use different water condition sequences rather than relying on historic traces. In the latter case, models may operate as though the future is known with certainty.
  • Water management models should include the full set of opportunity costs for water supply, power generation, flood protection and groundwater pumping. This implies that some type of linkage should exist between these types of models.

Using floods to replenish groundwater

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ALMOND ORCHARD FLOODING

M.Cubed produced four reports for Sustainable Conservation on using floodwaters to recharge aquifers in California’s Central Valley. The first is on expected costs. The next three are a set on the benefits, participation incentives and financing options for using floodwaters in wetter years to replenish groundwater aquifers. We found that costs would range around $100 per acre-foot, and beneficiaries include not only local farmers, but also downstream communities with lower flood control costs, upstream water users with more space for storage instead of flood control, increased hydropower generation, and more streamside habitat. We discussed several different approaches to incentives based on our experience in a range of market-based regulatory settings and the water transfer market.

With the PPIC’s release of Water and the Future of the San Joaquin Valley, which forecasts a loss of 500,000 acres of agricultural production due to reduced groundwater pumping under the State Groundwater Management Act (SGMA), local solutions that mitigate groundwater restrictions should be moving to the fore.

Don Cameron at Terranova Ranch started doing this deliberately earlier this decade, and working with Phil Bachand and UC Davis, more study has shown the effectiveness, and the lack of risk to crops, from this strategy. The Department of Water Resources has implemented the Flood-MAR program to explore this alternative further. The Flood-MAR whitepaper explores many of these issues, but its list of beneficiaries is incomplete, and the program appears to not yet moved on to how to effectively implement these programs integrated with the local SGMA plans. Our white papers could be useful starting points for that discussion.

(Image Source: Chico Enterprise-Record)

 

 

 

Looking for pumped storage in all the wrong places

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castaic_power_plant

LADWP is proposing to spend $3 billion on a pumped storage facility at the Hoover Dam on the Colorado River. Yet, LADWP has not been using extensively its aging 1,247 MW Castaic pumped storage plant on the State Water Project in the pumping recovery mode. Instead, LADWP runs it more like a standard hydropower plant, and uses pumping to supplement and extend the peak power generation, rather than using it to store excess day time power. And the SWP’s 759 MW pumped storage plant at the Hyatt-Thermalito powerhouse at Lake Oroville has been not been used effectively for decades.

The more prudent course would seem to be to focus on refurbishing and updating existing facilities, with variable speed pumps for example, to deliver utility scale storage that can capture excess renewable energy generation nearer large load centers. The State Water Contractors should be incented to upgrade these facilities through contracts with the state’s electric utilities. Unfortunately, no direct market mechanism exists to provide a true value for these resources so long at the California Public Utilities Commission and the California Independent System Operator avoid developing full pricing. As it stands, the current pricing scheme socializes and subsidizes a number of electricity services such as transmission, unit commitment decisions, and reliability services.

Repost: Wind capacity blows past hydro to become most plentiful US renewable | Utility Dive

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Installed wind capacity is more than 82,000 MW, according to a trade group, making it the nation’s largest renewable resource ahead of hydro.

Source: Wind capacity blows past hydro to become most plentiful US renewable | Utility Dive

An economically attractive environmental solution in peril

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The agreement to take down PacifiCorp’s dams on the Klamath River is in peril. In 2006 we showed in a study funded by the California Energy Commission that decommissioning the dams would likely cost PacifiCorps ratepayers about the same as relicensing. That mitigated the economic argument and opened up the negotiations among the power company, farmers, tribes, environmentalists and government agencies to came to an agreement in 2010 to start decommissioning by 2020.

The agreement required Congress to act by the end of 2015 and that deadline is looming. Unfortunately, there are still opponents who mistakenly believe that the project’s hydropower is cheaper than the alternatives. In fact, the economics are even more favorable today whether PacifiCorp uses natural gas or renewables to replace the lost power. And this analysis ignores the benefits to the Klamath fisheries from decommissioning. It’s too bad that bad simplistic economics can still get traction in the legislative process.