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Charging Electric Vehicles: The Challenges Ahead

Forget the latest Tesla announcement, writes John Massey. What is more important for the future of electric cars is how we will solve the challenge of charging them. Massey, an independent energy analyst and trainer, discusses the four main challenges of EV charging and concludes that the outcome of the process will depend on the interplay between electricity supply options, market operations, grid costs, policy choices and consumer behaviour (both rational and irrational).

Forget the latest Tesla announcement, the fanciest new concepts, or the scramble of traditional automakers to add electric drivetrains to their product mix. Yes, electric vehicles (EVs) will get cheaper, better and more diverse: that’s just inevitable technology progress.

What you should be focusing on is charging them up. The most challenging and disruptive changes lie within the electricity system. Here I’ll give just a brief flavour of the issues, divided into four sections as follows:

  • The Electricity Mix
  • Distribution Networks
  • Fast Charging
  • Autonomous Vehicles

My aim is to get you thinking, so I’ll be raising far more questions than I answer!

I’m certainly not raising these questions because I’m pessimistic of solving them – quite the opposite. But it’s only by asking them that we can start to develop solutions and identify new business opportunities which will take us in the right direction.

The electricity mix and price signals

At a macro level, the overall increase in electricity demand due to EVs is likely to be just a few %, often less than 10%. On the one hand that doesn’t sound a lot. Nevertheless it’s still a significant chunk of new power generation capacity (or an increased utilisation of existing capacity). At the very least it could reverse the trend of decreasing electricity use seen in markets like here in the UK.

More significant than average changes in demand, will be when these changes occur – and how they fit with changing supply.

For example, in cool northern climates demand is already greatest in the winter. The additional demand from EVs may be enhanced in the winter too, as a result of their reduced efficiencies in cold weather: meaning more charging is needed to achieve the same mileage.

One UK analysis concluded that in a town with a population of 6,800, just 900 EVs entering the system could lead to brownouts

The UK is one market where the removal of coal is a carbon policy priority. It’s one that has been progressing well: coal has been disappearing from the electricity mix at a rapid rate in recent years. In 2017 however, during the top 10% hours of highest electrical demand, coal provided a sixth of Britain’s electricity. Those peak demand hours occur during early evening cold winter evenings – just when many people are arriving home and in temperatures where EVs are operating least efficiently. So when the coal is gone (as is government policy), what will replace both that missing supply and the additional requirement as EVs push demand up?

The rise of EVs adds extra emphasis to a question of dependable supply capacity that existed anyway.

On the other hand, in summer there is likely to be excess energy available in the middle of a sunny day, due to large solar capacity. Will EVs be able to soak up that excess? That would be great, because prices, at least at a wholesale market level, will be low. Adding EV demand could avoid both these prices going negative and the curtailment of clean energy. Cheap charging would be good for consumers and increased demand would boost the value of solar energy. But does the middle of a sunny summer day coincide with when people want to be charging? If it doesn’t, will prices – when at the retail level – prove low enough to shift their behaviour?

There will also be times of plentiful or excess energy due to wind, but since these are much more variable, it’s impossible to model the impact based on any regular schedule. Price-taking here would need to be a much more ad-hoc, automated response.

Of course the volatility of prices in a system depends strongly on the flexibility of the system itself. Extremes, whether high or low (even negative) are symptoms of inflexibility. Excesses of energy may prove more attractive to store elsewhere (in stationary energy storage systems) or to export, or to utilise through other demand response mechanisms (refrigeration, heating and more). Indeed as EV fleets expand, their aggregated charging response will itself likely become an important source of macro system flexibility, smoothing out the very price signals that initially guided it.

Fast-charging could be key in overcoming anxieties around range. If you know you’ll be able to stop for just a short time, then leave with a battery full enough to get you where you are going, that’s one major inhibitor of EV uptake gone

It’s worth noting that where volatility is high and hence changes in tariff could prove attractive, concerns have already arisen around “changeover points”: for example multiple cars all starting to charge the moment a tariff change signal occurs. Systems do already exist to mitigate this though, delaying or spreading charging initiations to avoid unwanted local spikes in power draw from the distribution grid. (We’ll focus on those nasty spikes in the next section).

At larger penetration of EVs though, how far can charging delays be pushed, without consumers missing out on tariff benefits or fretting over their state of charge?

Distribution networks and demand diversity

If everyone on your street decided to switch on their electric oven at the same time, a fuse at the local substation would likely go “pop”. Everyone would find themselves in the dark (with those electric oven owners limited to eating salad).

In other words, grid capacity is already sized around demand diversity, rather than scaled to accommodate synchronised maximum demands. This approach keeps costs down by avoiding sizing infrastructure to meet very, very unlikely scenarios. It isn’t aggregated energy that matters here, it’s power demand at any specific moment in time.

One key problem with the idea that EVs will automatically take advantage of low prices driven by excess solar or wind energy is that this could decrease demand diversity (if they all choose to start charging at the same time). And EVs, especially future ones with faster chargers, are bigger draws on power than electric ovens!

One UK analysis concluded that in a town with a population of 6,800, just 900 EVs entering the system could lead to brownouts (through a drop in the voltage of supply). At a more local level, a pilot project showed problems when just five 3.5 kW chargers were connected to a network cluster (with 134 dwellings) and charged at the same time. That project concluded that 32% of UK low voltage circuits (312,000 in total) would require reinforcing if 40% – 70% of customers had EV’s with 3.5 kW chargers (i.e. very slow ones, with 7kW now becoming the norm). That was estimated as a present-day cost of around £2.5bn. Ouch. Luckily pilots aren’t just about identifying problems, they’re about solving them too. This same one tested a system to avoid much of that reinforcement cost by managing charging when local grid capacity started to be strained.

In the absence of diversity, managed charging is thus essential in addressing the potential conflict between cheap energy supply and expensive grid upgrades. It shouldn’t just be driven by least-cost wholesale electricity, starting the process as soon as this is available. It should account for grid constraints and distribution costs too. It’s also worth noting that managed charging itself imposes some costs, such as installation and maintenance of the required communication infrastructure.

In practice, distribution network upgrades won’t be a nationwide issue, certainly not at the start of the EV growth story. Some localities – wealthier urban streets – will have greater concentrations of EVs and/or greater concentrations of larger EVs (attached to higher-power chargers).

This raises interesting policy and socioeconomic questions.

Should the costs of local grid upgrades be spread across other electricity consumers, those elsewhere and even without EVs, in order to enable drivers to access to cheap electricity? Or should demand charges (based on each consumer’s peak power requirement) become a much more significant element of domestic electricity bills?

Should electricity charges, whether based on demand or on energy consumption, become differentiated down to the local level through new “nodal marginal pricing” regimes. These take account of specific congestion conditions within the grid, with high prices discouraging consumption where congestion is high. Such pricing schemes exist at the wholesale market level in a number of electricity markets around the world, but not yet at the distribution level.

National Grid have suggested it might be better to build a few thousand super-fast charging forecourts of >3 MW capacity rather than undertake a large scale rebuild of the domestic electricity infrastructure

Is a better solution to avoid charging EVs directly from the grid; charging stationary storage systems instead. That could be done when it makes most sense in terms of grid capacity and/or energy cost, spreading a low power draw through the day. Then EVs could charge from this stationary storage, at a faster rate, when it makes most sense for a consumer’s own mobility needs. What are the economic and aggregated energy implications of that approach, given that each extra storage roundtrip involves energy losses?

If the solution is to be a combination of several or all of these options, which combination will be both comprehensible and acceptable to consumers, while efficient in terms of reducing grid reinforcement costs? Are these goals even all deliverable at the same time?

Fast chargers and “filling stations”

The last section focused on home-based charging – and it certainly seems reasonable to assume that, unless unable to, most EV owners would like to have a charger at home. Nevertheless, distribution constraints mean that unless they are prepared to pay for the privilege of higher power, this charger will likely remain slow.

Yet there is clearly lots of interest in fast charging, with ever-increasing sets of headline numbers around how powerful these will be (350kW being the highest I’ve seen thus far).

Fast-charging could be key in overcoming anxieties around range. If you know you’ll be able to stop for just a short time, then leave with a battery full enough to get you where you are going, that’s one major inhibitor of EV uptake gone. It doesn’t matter that most people might have 90-95% of their journeys within the range of EVs – that other 5% can still give cause for concern. Not so, if one quick stop solves that rare problem.

In the UK, around 40% of car owners live in homes where installation of a charger remains problematic (for example shared residences or those without off-street parking). For them, the need to visit a “filling station” may be a necessity rather than a nicety. It remains to be seen whether these public or privately-operated chargepoints will be in similar locations as now (as Shell, for one, hopes) or elsewhere – supermarkets, car parks and so on.

Utilisation and demand diversity will prove key to identifying the grid requirements, the costs and hence the business cases in any eventual outcome.

Fast charging may flatten aggregate demand curves (i.e. a macro system impact), but increase local capacity issues (through short-but-high peaks at specific locations). Bear in mind that ten 350 kW chargers would require an infrastructure capable of handling 3.5 MW. In current fossil-fuel forecourts, 20 pumps are not uncommon: that would require 7 MW of infrastructure support in a single spot. Proposed solutions to very high demand chargepoints range from siting them close to high-speed electrified rail lines, to utilising stationary battery storage too (as suggested for domestic charging in the last section).

However connected, fast and super-fast chargers will compete for charging revenue with slow and domestically-sited charging demand. Opinions vary on which will predominate.

National Grid have suggested it might be better to build a few thousand super-fast charging forecourts of >3 MW capacity rather than undertake a large scale rebuild of the domestic electricity infrastructure. As they put it: “it may well be that the charging from home option may not be in the long term interest of the consumers even with smart chargers.”

That approach conflicts with one which links domestic charging and a consumer’s own electricity supply: charging their car from their own PV rooftop, perhaps with stationary storage too. That’s an attractive, “in control” concept for many consumers. It also removes some other concerns they may have. Would relying on a fast charging station mean queues at peak times? Would every “pump” be interoperable with every car?

Current opinion appears to favour relatively slow home-charging as the dominant mode, while recognising rapid charging networks will certainly be required. They may be used relatively infrequently, as emergency, “unplanned” charging options or on rarer long journeys – and will likely be priced as such. At a recent conference in London, National Grid suggested that as few as 50 ultra-rapid chargepoints in key locations could solve range anxiety issues here in the UK; and at relatively minor cost.

Beyond “slow” and “fast” charging, there’s wireless charging. Who’s to say we’ll need to plug in at all: maybe one day the battery charge will be topped up at every parking spot? Or a little bit added every time we pause, at a junction or traffic light? If that seems like science-fiction, be aware that the technology already does exist.

Fully-autonomous EVs

The impact of fully-autonomous EVs is one which promises to be significant at all levels within the electricity system, both macro and local.

One key question concerns overall energy use. Will AEVs increase or decrease driven miles? There are a lot of variables that feed into answering that question.

How many AEVs will simply replace private vehicle ownership on a one-to-one basis? How many will be shared AEVs (SAEVs), whereby a single car replaces several privately owned ones, through car sharing or “Mobility as a Service” (MaaS) schemes? In either case, will the AEV experience prove so pleasant that more journeys are made, perhaps even reducing demand for public (mass) transport? Or will route-sharing and efficiency algorithms, plus other SAEV fleet management software get people from place to place with less overall driven miles?

There is some evidence that ridesharing may increase usage: one study concluded that, between 2013 and 2016, ridesharing services increased miles driven in New York City by 600 million.

From an individual charging and network perspective, the requirements and changes created by AEVs are highly uncertain. Nevertheless, we can theorise some impacts.

Some analysts suggest shared fleets will favour centralised super-charger locations, cost-optimised for fleet-owners by locating close to substations and away from congested grid nodes

It is likely that SAEVs and MaaS businesses in particular will depend on access to fast charging: after all, time spent charging a battery is time not spent charging customers. The latter is an opportunity cost, which will certainly exceed the electricity charging costs.

On the other hand, a shared vehicle fleet will be smaller than an individually-owned one. That probably mean fewer chargers overall will be needed, to service fewer cars; though these cars will need to charge up more often.

Some analysts suggest shared fleets will favour centralised super-charger locations, cost-optimised for fleet-owners by locating close to substations and away from congested grid nodes. On the other hand ride-sharing is likely to be particularly attractive as a business within densely populated areas, where utilisation rates are high but centralised charging sites may be limited.

Location and timing issues will be interlinked. Perhaps peaks will occur before and after each commute period? But where will these occur? For the morning commute, an “after” peak might take place at central city locations close to which cars have converged. But where will the AVs have charged up prior to rush hour? Will they spend the night at suburban charging centres, or themselves first commute out of the city in order to bring people back in?

New behavioural patterns of mobility create big implications for the electricity grid. Will new behaviours drive grid changes or will grid constraints limit behavioural change? The answer is probably just a question of the timeframe we choose to consider.

Confused? I hope so!

If you thought the most interesting issues in the transition to electric vehicles lay in the progression of the vehicles themselves, then hopefully I’ve changed your mind.

Instead I encourage you to look far more closely at how all those batteries will be charged, both from a macro (energy mix) perspective and from a local grid network one too.

How many chargers will we need, where will they be and who will operate them?

The road to answering such questions will be winding and awash with intersections and route choices. It will involve business models which may make sense in the short-term but prove to be dead-ends in the long-run. It will depend on the interplay between electricity supply options, market operations, grid costs, policy choices and consumer behaviour (both rational and irrational).

It will be an exciting journey!

Editor’s Note

This article was first published on his blog Grey Cells Energy and is republished here with permission.

Original Post

Content Discussion

Bas Gresnigt's picture
Bas Gresnigt on February 9, 2018

The question I miss:
“How big will be the share of hydrogen cars?”

As:
– those are more easy.and just as quick to refill as present fossil fuel cars, they will be an important share of future cars. Also because those will have a longer range without refill than present cars;
– the needed hydrogen will be locally produced at the refill station (or at home) via cheap mass produced unmanned Power-to-Gas facilities (as now in pilots in Germany);

those wiil take important share of the future car fleet.
Especially since those don’t have the cumbersome slow recharge problem of batteries, which makes many consumers feel uneasy.

Bob Meinetz's picture
Bob Meinetz on February 10, 2018

Bas, hydrogen cars are fossil fuel cars.

98% of hydrogen comes from steam-reforming, a process which strips the hydrogen atoms from fossil-fuel methane (CH4). The carbon atom at the center of CH4 doesn’t disappear, but quickly combines with two oxygen atoms to create CO2 – carbon dioxide – which is released into the atmosphere to help its brethren warm the Earth and acidify the oceans.

The main purpose of the 2% of hydrogen from pilot “unmanned Power-to-Gas facilities” is promotional – to create the appearance solar panels and wind turbines are generating appreciable amounts of electricity, instead of enriching international oil companies at the expense of the environment.

Roger Arnold's picture
Roger Arnold on February 11, 2018

The article asks good questions. I agree with Dr. Massey that the charging infrastructure and issues around it will ultimately be more critical to the future of EVs than EV technology per se. “More critical” in the sense of more likely to be limiting, more in need of planning attention and regulatory support. Battery technology and issues of vehicle performance are being well taken care of by competition among vehicle manufacturers, but charging infrastructure is part of the commons. It’s easily neglected until shortcomings with it rise to the crisis level.

Part of the problem for EV charging lies in the way a cumbersome regulatory process plays out with the user interface for EV charging and human behavior. My son drives an EV, and last year we had a level 2 charger installed at our house. Owning an EV made our household eligible for a “time of use” rate plan from PG&E. It gave us a lower rate for off-peak electricity use, and was supposed to help the utility balance supply and demand more intelligently. But there’s no interactive signaling involved. The TOU rates are tied to fixed time periods. And the time periods used are obsolete. They don’t reflect and don’t do anything to help with California’s infamous “duck curve” supply problem.

As a household, we’re not seeing much benefit from the TOU rates. Although our son’s car can be set to defer overnight charging to the 11:00 PM start of the “off peak” use period, he doesn’t regularly use that feature. The home charger is his main “filling station”, and he normally wants top off the battery charge as soon as he gets home. That leaves him free to go out again without worrying about having enough charge.

In theory, the car could learn his driving habits and / or ask him about when he expects to go out again. Based on its state of charge and expected next use, it could negotiate the most favorable charging periods with the utility. It’s not a technical problem; the car already has all of the capabilities needed, including internet connectivity. The problem is lack of standards and regulations to support such use.

Bas Gresnigt's picture
Bas Gresnigt on February 12, 2018

Not for long in a society with abundant wind & solar power!
In those Power-to-Gas outcompetes other processes to produce hydrogen because electricity will often cost less than 1cnt/KWh and mass produced PtG facilities will be cheap.

Considering the fast progress, due to the ongoing major research and developments in Germany (also by US MIT), there is little doubt that PtG will become mainstream in a decade in Germany. US will probably follow roughly a decade behind.

Bob Meinetz's picture
Bob Meinetz on February 12, 2018

That leaves him free to go out again without worrying about having enough charge.

Precisely Roger, and that’s why TOU pricing will never accomplish to what it aspires.
It’s nothing more than a transferral or PG&E’s responsibility to provide sufficient capacity to its customers as a cost in convenience. In essence, your son has to worry about having enough charge so that PG&E doesn’t have to worry about closing Diablo Canyon.

In theory, charging lower rates during the day would help to deal with solar overgeneration, and some large commercial customers participate in mandatory TOU pricing plans where the utility remotely cuts their access to electricity when peak demand threatens grid reliability. A paper from the Energy Institute at Haas/Berkeley explains why it only results in additional cost for retail customers.

As it turns out, this situation results in large welfare losses due in large part to the time-invariant rates being charged to retail electricity customers. Marginal benefit equals marginal cost only by chance and for fleeting moments during the day or year, implying chronic over- or under-consumption with respect to the social optimum. Generation is overbuilt as insurance against blackouts. And marginal firms (even those with low market share) face a sharply inelastic demand curve, giving them the capability to exercise market power during hours of system peak.8 The cumulative welfare loss due to these features of the market have been estimated at approximately 5-10 percent of value in the wholesale electricity market (Borenstein & Holland [2005]).
These facts are not lost on regulators, and most economists acknowledge the importance of better understanding market outcomes in this setting. In his work on peak load pricing, Steiner [1957] laments ‘an almost total absence of empirical evi- dence as to the importance of the potential shifting peak…’.

https://kkjessoe.ucdavis.edu/ResearchPapers/JR_MandTOU.pdf

Nathan Wilson's picture
Nathan Wilson on February 12, 2018

Sure, there may be some role for hydrogen cars, but it will surely be small compared to the BEV market. The advantages of hydrogen are few.

“those [hydrogen cars] will have a longer range without refill than present cars”

Compared to gasoline cars, that’s delusional. Hydrogen, at 10,000 psi has 6 times less energy density than gasoline, and must always be stored in a tank with a round cross section. Gasoline is usually stored in a tank which is shaped to fit under the rear seat (i.e. a location which is protected in collisions, and not convenient for other uses). Hydrogen tanks will always go in the trunk area, and will always subtract from the available cargo area.

Fuel cell drive trains (which are usually battery-hybrids) are only about 20% more efficient than gasoline-battery hybrids, which is far too little to make up for the poor energy density.

“the needed hydrogen will be locally produced at the refill station”

This works fine for demonstration systems, but is simply the wrong solution for a renewable-rich grid. Large refueling station H2 tanks are bombs waiting to go off, so they must always be of limited size, generally one day’s worth or less, thus they can’t preferentially produce only when electricity is abundant. Distributed H2 generation is mostly a base-load application, and lacks economy of scale. Hydrogen cars can’t deliver the hydrogen economy benefits without pipelines to remotely located storage. But worst of all, unlike BEVs, H2 offers no advantages compared to gasoline for the end-user (pollution control is a societal benefit, not a buyer benefit).

I should mention however, that ammonia (NH3) for long haul trucks is a very good solution. Ammonia can be stored as a chilled liquid which is not pressurized, which greatly reduces the danger of fuel leaks and pipe-breaks, but heavy trucks of course never re-fuel in residential areas, so it’s less of a problem anyway. Ammonia can be delivered to refueling stations by pipeline or truck with good economics in either case. The trucking market will be easier to convert than personal cars, since a tiny cost advantage will take precedence over other buyer preferences.

Nathan Wilson's picture
Nathan Wilson on February 12, 2018

Great points. Note also that if utilities did implement real-time time-of-use metering, they’d have to implement very strong cyber security to prevent cyber attack from crashing the grid. The addressing the PV-induced duck curve also requires widespread use of daytime chargers (i.e. at the workplace), which is yet more infrastructure that’s needed.

In contrast, with a nuclear-rich clean energy grid, fixed time-of-use pricing works fine for BEVs, using homecharging. With nuclear, the off-peak power always occurs at nights. Just make a rule that timer activated charging must randomize the start-time, over say, a 30 minute period. That way if the published discount rate starts at midnight, the fleet will ramp-up gradually between 12 and 12:30. Note that Teslas already implement a random start delay when resuming charging following a power-outage; that’s another rule that must be implemented universally for grid-friendliness.

Jarmo Mikkonen's picture
Jarmo Mikkonen on February 12, 2018

If Germany has abundant wind and solar, why are they building a massive fossil fuel pipeline Nord Stream 2 to import even more natural gas from Putin?

To me, this underlines the fact that Germany still gets almost 80% of its energy from fossil fuels.

Engineer- Poet's picture
Engineer- Poet on February 13, 2018

You can do more than random timer-activated charging.  Charging can be ramped at almost any desired rate, and vehicles could easily shape their load curve to match the curve of available generation and complete charging by a specific time.

This has major implications for grid management.  If capacity that isn’t needed at midnight will be essential by 00:30, the ISO is going to have a daily headache.  However, if charging starts a slow ramp at 22:00 (or earlier or later depending on grid-frequency detection) the utility has a much easier time dealing with it.  The goal should be to fill in the valley of total load and make it as flat as possible for FF generators, or follow the generation curve for unreliable generators.

Bob Meinetz's picture
Bob Meinetz on February 13, 2018

EP, no doubt EVs or their chargers could adjust their load curve to the curve of available generation. But why should a customer be responsible for adjusting his/her charging needs to the availability of energy from a utility monopoly, one which is ostensibly required to serve the public interest?

Engineer- Poet's picture
Engineer- Poet on February 13, 2018

why should a customer be responsible for adjusting his/her charging needs to the availability of energy from a utility monopoly

Because that’s the least-cost and least-pollution way to meet the needs, allowing the benefits to be shared between them and the broader society.

one which is ostensibly required to serve the public interest?

Because it’s in the public interest.

The public utility has the obligation to serve everyone while maintaining reasonable cost to the customer and a host of social goods, such as minimizing pollution.  Maintaining enough capacity to handle massive spikes in demand as e.g. a million EV chargers switch on the very second that off-peak rates come into effect is going to have unreasonable costs and probably other ill-effects such as startup and idling emissions.  Leveling the demand curve allows the total energy requirement to be met at minimum cost and probably optimum efficiency (lowest emissions) also.  Sharing the cost savings with drivers cuts them in on the benefits of their restraint, and the benefits of reduced emissions flow to everyone.

Bas Gresnigt's picture
Bas Gresnigt on February 13, 2018

Near all investment is done by the Russian gas supplier.
Reasons:
– lower costs than the existing over-land pipelines. Transit countries such as Belarus, Poland, etc. demand and get major rights-of-way money for the gas which flows through the pipeline.

– more deliver security. E.g. Ukraine tapped from the pipeline which went through the country without paying. So much that Russian Gazprom had to stop delivery, and part of SE EU became very cold as there was not sufficient gas.
Belarus threatened to close the pipeline if Gazprom was not prepared to deliver them against a cheaper price. Etc.

– Other supply is needed as The Netherlands decreases the delivery of gas down to near zero within ~5years (the exploration of the natural gas causes small earth quakes, unacceptable in NL).

Note that near all German houses are heated by gas now.
Changing that to electricity implies an overhaul / upgrade of the German grid which takes decades….
The German climate is much colder than e.g. that in France,

Bas Gresnigt's picture
Bas Gresnigt on February 13, 2018

In the past people chose always for more easy / convenient transport.
Don’t think that will change soon.

H2 cars are far more easy / convenient than BEV:
– Range is much larger (the new Hyundai comes with a range of 800km)
– Refill is even more convenient than with petrol cars and just as fast.
No >20minutes frustrating waiting as with BEV’s for another 300km.

Ammonia may be a good alternative. I cannot judge that for now.

Bas Gresnigt's picture
Bas Gresnigt on February 13, 2018

In NL we are rolling out smart metering. The idea is that competing utilities then can offer rates such as the one hour ahead wholesale prices at the Power Exchange + an administrative fee, etc.
That the consumer can program his washing machine, etc. based on the pricing signals coming from the utility. etc.

Will still take a decade or so. Yet we are also a decade or so away from a situation in which wind + solar produce most electricity.
So we have time to experiment with pilots,

donough shanahan's picture
donough shanahan on February 14, 2018

Not for long in a society with abundant wind & solar power!
In those Power-to-Gas outcompetes other processes to produce hydrogen because electricity will often cost less than 1cnt/KWh and mass produced PtG facilities will be cheap.

If the price of the excess electricity is 1cent/kWh, then there is no way that the capacity producing it will be profitable.

Bas Gresnigt's picture
Bas Gresnigt on February 14, 2018

The market mechanisms operates!
At the present you can already see that the whole sale prices at the APX (Power Exchange Market) is frequently below 2cnt/KWh and often even below zero. So a smart buyer mechanisms can buy already at an av. price 1,5cnt/KWh during substantial part of the time.

The unmanned PtG facility simply stops when the price is >2cnt/KWh! Those stops will become shorter and shorter with the coming installation of more wind & solar, which implies cheaper and cheaper H2. Also because the mass-produced PtG facilities become cheaper and cheaper…

General price decrease of electricity
At the moment Offshore wind in the North Sea with delivery starting in 2022 is offered to be installed operated and decommissioned decently without any subsidy while the av. market price is expected to become ~€29/MWh.
Those bidders expect to use ~12MW wind turbines with CF’s of near 60%.

Those bidders have sound business cases as they have to deliver their business case to Dutch govt, whose accountants will check them in full detail as part of the selection procedure to grant a license to operate an offshore wind farm.

Experts expect that the fast price decrease will continue with the increase of the wind turbine size towards 20MW (=higher=higher CF, same maintenance visit costs while production is much higher, etc.). So new offshore wind farms in 2030 will have cost prices of near 1cnt/KWh.

Just consider the fast price decreases of wind & solar in the past 15years… No reason to assume that the decreases will end in next ~15years!

donough shanahan's picture
donough shanahan on February 16, 2018

At the present you can already see that the whole sale prices at the APX (Power Exchange Market) is frequently below 2cnt/KWh and often even below zero. So a smart buyer mechanisms can buy already at an av. price 1,5cnt/KWh during substantial part of the time.

While we are seeing such prices sometimes, and negative prices, these prices are being driven by electricity that has priority dispatch. And these are of course distorted by subsidies which are paid after the wholesale price is agreed. That means looking at those prices is not the total story. Though you already know this so why ignore this key point?

At the moment Offshore wind in the North Sea with delivery starting in 2022 is offered to be installed operated and decommissioned decently without any subsidy while the av. market price is expected to become ~€29/MWh.
Those bidders expect to use ~12MW wind turbines with CF’s of near 60%.

Based on extremely low cost of capital. And we still wait for those contracts to be signed. And no, they do not expect 60% cf. They do not yet have business cases as the funding is yet to be arranged and the contracts to be signed!.

Just consider the fast price decreases of wind & solar in the past 15years… No reason to assume that the decreases will end in next ~15years!

Yes there is an only an utter fool would continue to assume that prices decreases or efficiency gains would continue indefinitely. Your point suggested that increasing cf was a big reason for the cost reductions. Cf, by your numbers is at its limit.

Furthermore the cost curves of the past are no different, I repeat, NO DIFFERENT to other technologies such as mobuile phones, cars, CPI production facilities, gas turbines or whatever else you want to use. Yet you deliberately ignore that what happened to them in terms of cost reduction will also happen to turbine and solar production.

Bas Gresnigt's picture
Bas Gresnigt on February 16, 2018

…you already know this so why ignore….”

Because expectations are that whole sale prices will decrease further in the future. The cost prices of more and more new unsubsidized wind & solar will decrease to <2cnt/KWh.

Offshore wind in the North Sea …. ~€29/MWh.
…. They do not yet have business cases as the funding is yet to be arranged and the contracts to be signed!

So you didn’t read the RfP of Dutch govt and don’t know the EU rules which apply.
Bidders have to deliver with their bid, their full business case, etc. All to be verified and checked by Dutch govt accountants, engineers, etc (incl guarantees of important sub-suppliers, bank guarantees so the funding is guaranteed, etc).

Dutch govt wants to avoid that a bidder makes losses on the offshore wind farm because that may result in bad maintenance of the wind farm or a premature end or …
We don’t want to get a problem in our busy sea before our nice beaches…

The RfP follows the EU tender rules, so the RfP contains a proposed contract towards bidder has to agree and sign, or indicate at which points he cannot agree and why and which modifications he proposes…
If Dutch govt wants to agree with a proposed modification then it has to notify all bidders and every bidder gets a reasonable term to modify his bid if it affects his costs / business case.

… an utter fool would continue to assume that prices decreases or efficiency gains would continue indefinitely.

I did not state that.
However as many experts in the fields confirm, there is enough space to improve efficiency, etc. so the price decrease will continue for the next ~15years.
Wind turbines will continue to increase in size until at least 20MW (check the EU study), the near 100m long blades will be produced by highly automated machines (still mostly skilled hand work), maintenance visits to those huge wind turbines will decrease to less than once in 3 years or less, vibrating the foundations in the sea bottom will see a revolution in a few years, etc. etc.

Of course once designs & production (tools) are fully developed, the cost decrease will gradually vanish.
But we are still rather far away from that point.

Regarding your example:
Note that you can now buy a smart phone for €100 with features and capabilities that are better than the smart phone that did cost 5 times more 7 years ago….

Mark Heslep's picture
Mark Heslep on February 19, 2018

The number one priority in consumer vehicle price decisions is sticker price.