Power Pricing and Energy Storage along the St Lawrence River System

Harry Valentine | Jan 12, 2010

The waterway system between Lake Superior and the Gulf of St Lawrence provides power generation and the capacity to store massive amounts of energy through pumped hydraulic storage. The well being of a population of several million people who live on both sides of the US-Canada border depend that hydroelectric power generation. At present, the pumped hydraulic storage installation at Ludington, Michigan is the largest of its kind along the waterway.

There is interest on both sides of the international border in increasing both wind power generation as well as nuclear power generation in the regions that lie within close proximity to the waterway. There is significant potential for offshore and even on shore wind energy generation along the shores of the Great Lakes. One group has announced plans for an offshore wind farm of 4400MW peak output for Lake Erie while other proposals involve the shores of the other Great Lakes.

The nature of wind power generation is often unpredictable and makes access to energy storage capacity essential. Having access to such storage capacity has the potential to enhance the long-term reliability and the economics of thermal power generation, especially nuclear power. In a market-driven pricing structure, power prices would be higher during peak demand periods that during the overnight off-peak periods.

Constant Power Prices:

However, Ontario observes a non-market driven pricing structure for electric power that disregards changes in market demand during the day, instead opting to maintain a cost price for power irrespective of actual market demand. Lower power prices during the overnight off-peak period can justify the cost of developing and operating large-scale energy storage systems. The absence of price fluctuations for electric power during the course of a 24-hour day essentially nullifies the economic case for energy storage.

Operating thermal power stations at constant temperature, constant steam (or gas) pressure and constant output throughout a 24-hour day minimizes the onset of thermal stresses. Such operation can extend useful service life and can greatly reduce long-term operating cost while increasing the return on investment. Thermal power stations are more likely to incur thermal stresses and resulting stress cracks due to having continually fluctuate system temperatures, pressure levels and power output throughout the day and every day to suit market demand.

Eventually, the build up of thermally induced stress cracks requires that part or all of a thermal power station be shut down to allow expensive repairs to critical components to prevail. Costs can typically run into the millions of dollars. The savings that would accrue from operating multiple thermal power stations at constant output, could justify part of the cost of developing some form of large-scale energy storage system. However, non-market driven costs may also apply to nuclear power generation in some jurisdictions that have a propensity for nuclear cost over-runs.

Idle Wind Turbines:

At night and especially during the winter months, powerful winds frequently and reliably blow over the Great Lakes. The constant 24-hour (partially subsidized) power price of $0.15 kW/hr in Ontario actually justifies the economic case of tilting the blades of wind turbines to prevent the rotation of the drive shaft and subsequent power generation. Depending on the regulator and the power transmission companies, there may be potential to export wind-generated electric power from Ontario and across to the USA at an agreeable price and to a location where some form of energy storage capacity may be available.

Trans-Border Storage:

Until Ontario allows the power pricing structure to evolve into a system determined by market demand instead of by government decree, there may be an economic case to sell excess off-peak power from Ontario at attractive prices into USA-based storage systems. Such storage systems could be located along the waterway that connects Lake Superior to the Great Lakes and be covered by and subject to some form of unusual international agreement. Such agreements could be implemented at Niagara Falls where NYPA could then theoretically generate greater output than Ontario Power Generation between Lake Erie and Lake Ontario.

Essentially, New York Power Authority would operate pumped hydraulic energy storage while Ontario Power Authority would not, despite being "just across the border" and practically at the same longitude and latitude. The agreement could allow NYPA to install pumping turbines as well as additional tunnels and runners at Niagara Falls to generate additional power during peak periods, using the volume of water they had pumped to higher elevation during the off-peak period.

Powerful winds regularly blow over the eastern shore of Lake Ontario toward an abundance of high elevation sites in the Adirondack region of Northern New York State, where there are hundreds of possible locations to install wind turbines. During windy off-peak periods, the wind turbines could supply hundreds of mega-watts of power to a storage system. One option for NYPA in that region would be to develop an underground pumped hydraulic system immediately downstream of the Moses-Saunders power dam near Massena NY.

Geological research from Clarkson University dispelled an earlier fear of a possible geological fault under the St Lawrence River near the Moses-Saunders power dam. During 1944, an earthquake devastated a portion of the built-up region near the location of that dam, with an epicenter believed to have been under the Adirondack Mountains if not as far south as the Catskill Mountains. Clarkson researchers later discovered that most of the severely damaged buildings had been constructed above LEDA clay that liquefies when subject to vibration such as earthquake tremors.

In the remote event that Ontario actually allows for a market-driven pricing system to eventually evolve for electric power, both NYPA and Ontario Power Generation could jointly install pumping turbines into the Moses-Saunders power dam to pump water between Lake St Francis and Lake St Lawrence. Such an option would depend on the installation of similar pumping turbines at the power dam at Beauharnois along the St Lawrence River near Montreal. Evolving initiatives that are occurring along the lower St Lawrence River in Quebec could provide for such opportunities.

Initiatives in Quebec:

There are proposals to modify the Lower St Lawrence River between Montreal and the Gulf of St Lawrence to allow the new generation Panamax 2 vessels access to a modified terminal at the Port of Montreal. These ships sail with 50% greater length and 50% greater beam (width) that earlier generation vessels that sailed the river. The keel depth or draft is being increased from between 25-feet and 32-feet to between 45-feet and 60-feet draft for the newer vessels. One proposal for the partial unloading of the large vessels in the Gulf of St Lawrence and allow them to carry reduced loadings to Montreal.

There are numerous ways to allow deeper draft vessels to sail the lower St Lawrence River while conserving water and providing new opportunities in power generation as well as energy storage. Besides dredging or deep dredging the riverbed, it would also be possible to install control dams with optional power generation (and hydraulic pumping equipment) between the river shore and several islands in the river to reduce overall volume flow rate. While unpopular, it would be possible to install navigation locks along the lower St Lawrence River to provide deep-draft, wide-beam ships with passage to Montreal.

Initiative Spin-offs:

The aforementioned initiatives that are possible along the lower St Lawrence River can help conserve water in the Great Lakes and provide new opportunities to generate electric power and store energy hydraulically between Lake Ontario and the Gulf of St Lawrence. It would become possible to pump water to higher elevation from the confluence of the Ottawa River and St Lawrence River into Lake St Francis, with subsequent potential to pump water to higher elevation from Lake St Francis into Lake St Lawrence and the upper St Lawrence River.

Hydro Quebec owns a nuclear power station of 645MW output while Quebec has installed over 2000MW of peak wind generation capacity. Installing pumping turbines in the power dams between Montreal and Lake Ontario would make more efficient use of wind energy in Northern New York State to the east of Lake Ontario, Western Quebec north of Montreal and Eastern Ontario. Quebec has much on-shore and offshore wind energy potential along the eastern coasts of James Bay as well as Hudson Bay and within close proximity to Hydro Quebec's James Bay hydroelectric installations.

There is potential to develop pumped underground installations immediately downriver of the power dams at Massena NY and the southwest of Montreal. Each such installation would divert less than 10% of the outflow from the power dam to generate 1000MW during peak periods. A curved breakwater near a possible Massena facility could divert a greater proportion of the downstream water flowing from the power dam into the ship navigation channel downstream of Lake St Lawrence, thereby assuring sufficient water depth for the ships.

An underground pumped hydraulic storage battery located within close proximity to Montreal would have the potential to provide back-up emergency service. During the winter of early 1998, Montreal was literally without power for several days during a severe ice storm and has through its history endured prolonged power outages. There is hard impervious bedrock at the power dam near Montreal that is favorable for the development large excavated underground chambers located up to 2000-ft below river surface and for the purpose of pumped hydraulic storage.


  • Ontario's non-market driven pricing structure for electric power undermines the economic case for large-scale energy storage. This pricing structure could see wind turbines remain idle during the off-peak overnight periods in regions where powerful winds blow. One possible alternative could see excess off-peak electric power from Ontario wind farms being sold at market prices to customers and markets outside Ontario.

  • Ontario and New York have the potential to jointly to develop their pumped hydraulic potential at Niagara Falls and at Massena-Cornwall, after both sides observing a pricing structure for electric power that reflects actual market demand during peak and off-peak periods.
  • Initiatives along the lower St Lawrence River between Montreal and the Gulf of St Lawrence could provide opportunity to develop pumped storage at 2-power dams between Montreal and Lake Ontario.
  • Hydro Quebec's reservoirs in the James Bay region have been known to fill to capacity during the springtime melt, leaving little or no reserve capacity. Excess overnight springtime power generation from the James Bay region could, in the distant future, be transferred into storage at other locations in Quebec.
  • Ontario's present pricing structure for electric power may justify the case to install pumped underground storage technology immediately downstream of the power dams at Massena NY and to the southwest of Montreal.
  • Related Topics


    I stopped reading when I got to this statement:

    << However, Ontario observes a non-market driven pricing structure for electric power that disregards changes in market demand during the day, instead opting to maintain a cost price for power irrespective of actual market demand. Lower power prices during the overnight off-peak period can justify the cost of developing and operating large-scale energy storage systems. The absence of price fluctuations for electric power during the course of a 24-hour day essentially nullifies the economic case for energy storage. >>

    On the contrary, Ontario has had an active ISO/RTO style market for many years. The prices are reported as HOEP and the market operator is IESO. Granted, they do not have the two settlement structure of their American counterparts and HOEP is a balancing market. They look most like Alberta (AESO) and Texas (ERCOT).

    Ontario also has an active retail power sector.


    My definition of a market price is a price that is generated independently of the price set by regulators. Ontario's power pricing is a regulated power price. For example, Ontario offers over 40-cents per kW/hr for solar-electric power . . . except that consumers pay a much lower price. Ontario also purchases electric power from wind farms and then resells tha power to the market. A market price would develop when a power producer sells directly to a customer at mutually agreed upon prices . . . not prices set by a regulator. Ontario and many other jurisdictions need to move beyond sudsidized prices for some sectors of the power market. In my view, there is too much regulation and too much subsidy going on in power markets like Ontario.

    Ontario has a competitive market both at the wholesale and retail levels already.

    IESO does not "regulate" prices. It administers a market. Prices are no more "set" by IESO than the NYSE "sets" the price for any stock. HOEP is set through a highly competitive bidding process. Buyers and sellers interact on the wholesale level through IESO.

    Ontario has a robust competitive retail pricing regime. Buyers and sellers interact all the time. Here is a primer on the subject published by the competitive power trade association.

    As for solar and wind, there is no place on the planet where either is competitive, and does not require massive mandates or subsidies to exist. It is simply too expensive for very many consumers to take much of an interest in it. If you impose market discipline on wind and solar, you will kill it.

    I believe you misunderstand Harry. You are correct in that Ontario's wholesale market that our independent generator companies sell into is fully competitive administered by the IESO. What Harry is talking about is what residential customers pay - we all pay fully regulated “prices” for energy set by Ontario's regulator agency the Ontario Energy Board (OEB). Incidentally the OEB regulates consumer natural gas rates too.

    Our residential utility bills are broken down into energy charges plus delivery charges, the latter going to the coffers of our local distribution-only utility companies. The energy bill funds collected are simply passed on through to generator companies. Utility companies must apply to the OEB for any delivery charge rate changes, whereas the energy charges on our bills are uniform throughout the province. Our energy rates are typically updated with small increases or decreases twice per year by the OEB after reviewing how much profit or losses the independent generator companies have reported to date.

    The Ontario Power Authority (OPA) is another provincial government agency responsible to administer all generation contracts, construction of new generation and transmission asset contracts, and is also in charge of conservation and demand management programs the government wants to foster within our utility companies. The government itself through the Ministry of Energy sets generator grid feed-in tariffs, and were recently in the news media introducing our new Green Energy Act establishing the most lucrative renewable source tariffs in North America for wind and solar especially. These tariffs are what Harry is talking about being heavily “subsidized”, since they are set way above our consumer energy billing rates.

    I am just going by what I quoted.

    Hello James, Harry and Bob:
    The issue that the present Ontario regulatory authorities have failed to grasp is that it is essential for both energy and transmission/distribution rates to vary with electricity system congestion.

    In order for end users to significantly change their energy usage profiles to relieve electricity system congestion at peak times they have to employ some form of energy storage. In order to financially enable energy storage the on-peak marginal electricity rate needs to be close to three times the off-peak marginal electricity rate. This three to one ratio is impossible unless the transmission/distribution charge, as well as the energy charge, varies with time. Ontario Hydro understood this matter back in the period 1965 to 1980, but after that every one familiar with this matter retired.

    The policy of a constant transmission/distribution charge per kWh has the practical effect of locking Ontario into use of peaking generation for load following. An extensive discussion of electricity rates, metering and electricity system congestion factor can be found at www.xylenepower.com/Electricity%20Contents.htm.

    I can attest to the fact that if major building owners are offered an electricity rate that financially enables energy storage, they will in fact invest in that energy storage.
    During the period 1979 to 1995 I was a major player in the operation and maintenance of such energy storage systems.

    Charles Rhodes

    The fact is Ontario has an extremely confused retail electricity market, from I presume some extremely confused regulators. While they claim to operate an open, free and competitive retail market for consumers, they then mandate installation of TOU metering on every retail customer and then by regulation set the three TOU time intervals and the exact prices per kwh paid for electricity in those time periods, which cover 24 x 7 every day of the year. So how's that "competitive"? For several years after initial "de-regulation" there were several competing retail companies knocking on our door trying to sign us up as retail customers, but I haven't seen a single one since the mandate for TOU metering was published.

    What it needs in an IMEUC market implementation, every generating entity competing to sell directly to every customer large and small via an automated computerized communications system, with the transaction costs covered by a peak-period rate rider.

    Len: I agree that Ontario's retail sector is ... confusing. They don't seem to be able to come to a coherent policy. I also have quibbles with their wholesale regime. Given the extensive congestion, they should introduce congestion pricing. They already have a multi-zone shadow market, why not implement it? Why not move towards nodal pricing?

    As far as IMEUC, I disagree that this is the right approach. It is too complex to be implemented. Consumers will not be able to understand it, even sophisticated consumers with experience. I prefer the two tier approach where we have a wholesale side operated by an ISO/RTO with a distinct retail sector. In any case, TOU pricing is essential.

    First of all, while Harry proposes some interesting ideas, I think large-scale pumped storage projects are going to be very difficult to get permitted on either side of the border. I also think they are probably not necessary if a pricing regime is put in place that makes it worthwhile for consumers to purchase residential-scale energy storage (for heating and cooling). Thermal storage for heat is widely used in Europe - in fact the first time I saw one of these devices was at the Northern Ireland grid operator's control center more than 20 years ago. Thermal storage for cooling is available in all sizes and is probably more economical and faster and easier to build than pumped storage plants that will ultimately be operated to minimize environmental impacts rather than for their intended purpose of minimizing electricity costs.

    Second, a proposal for retail pricing. I don't think it is necessary to require time-sensitive distribution and transmission costs other than perhaps at the same level of granularity as more traditional time-of-use prices. They're typically not that consequential and it would be too difficult and time-consuming to create them. However, for the energy component (ignoring the costs of feed-in tariffs and renewable subsidies for the moment):

    Set a price to beat that is perhaps 15-20% higher than today's standard fixed price/variable volume rate. Anyone who does not wish to take service under a dynamic or block-and-index price (described below) for whatever reason can pay the price to beat. These consumers now pay a premium because...

    Block-and-index pricing includes a fixed volume at a fixed price and any variations from that fixed volume are paid or pay at the prevailing spot (real-time) price. Customers who can predict their demand can hedge the cost of most of it, but they still have some incentive to reduce consumption when wholesale prices are high.

    Dynamic prices vary hourly and are tightly linked to wholesale prices (day-ahead or real-time). What you pay is determined by what you use and when.

    Consumers would not have to watch a screen. Devices are already coming to market that can automate the price response. If differentials between on- and off-peak prices are large enough, storage will make sense at the distributed level as much as it makes sense at the bulk power level. The difference is that consumers will make the choice rather than a body that must cater to the least common denominator rather than catering to individual preferences.

    Subsidies and the revenue required to make good on feed-in tariffs are a problem. The distort prices in ways that end up defeating many policy objectives. I'm still trying to figure out how to deal with them.


    I agree with you storage is much more likely to happen at the customer level rather than as many large-scale systems at the grid level. For example we consumers in Canada have been storing heat in residential hot water tanks for decades already, either from natural gas or electricity heating. There are also examples of air conditioner products on the market now that create ice during lower rate off-peak hours as a cold storage scheme.

    "Consumers would not have to watch a screen". I must agree your statement can be viewed as true if consumers were to implement a fully automated system in their homes with some of the emerging devices that will respond automatically to energy price signals. It remains to be seen however exactly what network in any given utility company these devices will communicate over to obtain energy price signals. The internet is an obvious method but the appliance companies implementing this capability in the emerging devices are mostly expecting to do so over AMI networks using smart meters equipped to broadcast price signals.

    Many smart meters are already deployed without the necessary software and extra radio hardware (typically Zigbee) to accommodate broadcasting price signals, as is the case in millions of smart meters in Ontario. Instead such orphaned smart meters would have to use their built-in radios for their AMI network, and the devices would also have to have these relatively expensive AMI radios built in (typically expensive proprietary UHF or microwave radios). Too, the prospect of large numbers of customers having multiple appliance devices in addition to their smart meters all talking to their AMI networks is scary to utility companies to say the least, with nightmares of security and network loading issues. That’s not say AMI networks are incapable of handling this kind of scalability and security, it’s a question of whether utility companies implementing AMI networks are willing to pay for this extra capacity.

    As a proponent of real-time energy monitoring myself, I would say there are other reasons why consumers should be able to watch a screen, meaning at least view one once and a while. The concept of an in-home real-time display was originally conjured up for multiple purposes:

    1) Educating consumers about the relative instantaneous power demands AND energy use levels over time of various loads in their homes.
    2) Illustrating when peak consumption periods are happening in their homes.
    3) Serve as a real-time total energy bill tracking device.
    4) Demonstrate the effects of energy conservation measures over time, or energy efficiency upgrades to appliances and their homes.

    Many utility companies, indeed all of them in Ontario, are now planning secure web-page account presentation tools that will address points 2 and 3 above, but will require consumers to login to their utility website to do so. This is a deterrent in my view because many consumers are not likely to habitually take the time every day or every week to d so. So why not have an automatic device that does this for you, one with a screen monitor.

    Just setting up and later changing the settings of multiple devices, especially if they are tied together in any sort of Home Area Network system, will require some sort of user screen or PC monitor with software. I doubt very much that consumers would be very happy in a house filled with devices that all independently monitor price signals and act independently of each other, they will want to know at times just what the state is of the various programmable devices collectively and why i.e. what exactly is the current energy price.

    Further to my comments above, emerging plug-in electric vehicles are being viewed by many as customer-level energy storage devices, since that is exactly what their batteries will do.

    Let me add that the current wholesale regime in Ontario (IESO) is more than sufficient to support pumped storage. Market changes are NOT required, although introduction of congestion pricing might marginally benefit. Charles point about onpeak prices needing to be 3x offpeak may have been true ten or twenty years ago, but I disagree today. It is the differential that matters, not the ratio.


    Having a screen to watch is fine. Having to continually make adjustments is not. Automation is a requirement. Having an in-home display is not absolutely necessary, but probably something folks will find very useful.

    You mentioned the problems that can arise if individual appliances are reporting back to the utility over its AMI network. Let's hope they do not design their systems this way because it will, indeed, become a disaster. As will any attempt by a utility to manage individual devices. Send out the prices via Internet, RF, AMI, whatever. Let consumers (with help) and appliances figure out how to use them. Any utility that thinks it can control millions of individual devices without creating a PR nightmare is not being realistic.

    In fact, the most practical way to approach energy management is to focus first on the largest end uses, which include space conditioning (cooling and heating), perhaps some flexible industrial processes, and EVs if they catch on.


    Rest assured all the utility people and meter manufacturers I have ever talked to have absolutely no desire to control anything behind their residential meters beyond cycling air conditioners and pool pumps that they have practiced already for years. The latter is being done lately using the pocket pager radio network and pager-equipped smart thermostats, totally independent of AMI systems. Beyond air conditioner cycling, consumer controlled home automation is the way everyone sees it all going.

    Most meter manufacturers also don't really want to incorporate handling comprehensive demand response management in their AMI systems either. They appear to prefer other third parties support it with stuff that communicates over the internet or cellular telephone networks to consumer devices or HAN systems.

    In spite of this the Zigbee Alliance people in my industry have quite successfully promoted their radio open standard as one of the best accepted methods for smart meters to communicate with residential demand responses. Initially I suspect the new residential appliances coming out will be Zigbee-equipped for talking directly to Zigbee-equipped meters, and later down the road, particularly if we ever see HAN automation take off, we will probably see residential HAN gateway devices appearing. These gateway devices will be either Zigbee-equipped or have an expensive proprietary AMI radio to serve as a single bridge device between the meter / AMI network and the customer’s HAN. The AMI radio version will effectively limit the AMI network loading to just one extra AMI radio node per customer in addition to the meter.

    BTW there is no technical reason why these single gateway bridge devices couldn’t also serve as an in-home display too if they had a screen. Such a product does not exist to my knowledge because no AMI network or smart meter supports it, yet.

    James, the differentials need to be pretty large before storage pays for itself out of market revenues. Some rough (and simplified) numbers. A pumped hydro plant costs $1500/kW, and the annualized carrying cost is somewhere around $225/kW. With 8 hours of storage, it will inject power into the grid around 2,000 hours per year (perhaps 2800 hours max). This requires that the average on-to-off-peak differential be between 8 and 11 cents per kWh. I'd be surprised if those differentials exist in Ontario. They do not exist in any US market I'm aware of. We may start to see differentials of this magnitude with significant penetration of wind energy that produces mostly off-peak. Systems with solar and wind won't see these differentials.

    I'm not opposed to storage. Where there are wholesale markets, storage becomes a pretty tough sell unless it is used for ancillary services like regulation, in which case the relatively high price of regulation and lower capital cost of a device with limited storage appear to match up well.

    On the other hand, I would dearly love to see retail rates that make thermal storage attractive. I think there are some sizable benefits to very small scale distributed storage (no siting, simple operation, consumer gets the benefit).


    The on-to-off-peak differential in Ontario currently set by regulators is
    9.3 - 4.4 = 4.9 cents per kWh, so you are right, no one in North America has anything close to 8 cents, yet. (Ontario's mid-peak rate is 8.0 cents.)

    All of Ontario customers will be on TOU by the end of this year, but currently most are still on flat rate with only Toronto Hydro having switched most of its 1 million plus customers to TOU. Ontario's flat rate is currently 5.8 cents for the first 1000 kWh, and 6.7 cents for all kWh above 1000.

    TOU rates and each rate's clock hours in Ontario have been set after extensive research into TOU consumption patterns, in an attempt to keep revenues collected for energy roughly “neutral”. This means if a typical residential customer practices absolutely no load shifting under TOU, their energy bills will be roughly unchanged as compared with current flat rate billing.

    Keeping total revenues collected “neutral” under TOU is obviously meant to prevent TOU from becoming a PR nightmare for the government, being a highly sensitive political issue with the public. But in my opinion, down the road after everyone is used to TOU billing, the province can later tweak the rates AND the differential upwards to collect more total revenues. And consumers will have no easy way to reconcile their TOU bills without pouring over daily consumption patterns. And if anyone complains, the government is likely to simply tell them to practice more load shifting to minimize their total bill increases.

    My last sentence is a big reason I believe the public will increasingly need real-time in-home energy display monitors, along with software to help analyze their consumption patterns as the best way to reconcile their TOU bills.

    Does anyone care that a completely proven and cost effective solution already exists? Vanadium Redox Batteries scale up, have zero environmental footprint, charge/discharge 100%, have zero cross contamination issues, zero heating, and fast response time. Read this Discovery Magazine article and then educate me please: http://bit.ly/4zNrRI

    Simple. Vanadium Redox batteries are very expensive. A 20 kW system costing $300,000 works out to $15,000/kW. It would have to cost less than $1500/kW to be cost competitive with pumped storage. It has to cost less still to displace gas-fired alternatives.

    Get the cost down and the world will beat a path to your door.

    Jack: I didn't mean to imply that the current price differential was sufficient, just that the IESO hourly pricing market could support pumped hydro. Thanks for the numbers, btw.

    There are dozens of large scale pumped hydro facilities all over the world, including the US with several on the US/Canadian border waterways, including Lake Michigan.

    If you are correct about the required 8-12 cent ($80-110) differential, then there is no place in North America that can support a new merchant pumped hydro facility. For example the 7x16 vs 7x8 price differential in ERCOT is $15-20. Add in regulation and spin revenues and you might get close.

    James Carson, RisQuant Energy

    I've been trying to figure out why the Ludington Unit was built. It produces 1872 MW (for up to 13 hours) at a cost of $327 Million in 1969. That works out to only $175/kW, so the economics on the site are much more favorable than others have indicated.

    I'm thinking either the landscape was simply very favorable for such as site, or some spare storage was needed or desired w.r.t. to the Cook Nuclear Power plant built nearby at approximately the same time.

    Jim Beyer, I think it was in anticipation of having cheap off-peak nuclear energy to charge the storage. I'm told Ludington is very profitable. At $175/kW, it should be! Using the same sample numbers I cited earlier, differentials of about $2.50 would be adequate.

    And now that I think about it, the 8-10 cents per kWh don't include the cost of conversion losses. On that basis, the differentials would have to be a fair bit higher.

    Although it's been a couple of decades now, I did several evaluations of storage technologies. The energy cost savings were never nearly enough to offset capital and operating costs.