Guest Post – NYS Energy Storage

Richard Ellenbogen frequently copies me on emails that address various issues associated with New York’s Climate Act.  I asked his permission to present his analysis of the New York State Energy Storage Roadmap Report as a blog post here.

I believe that he truly cares about the environment and the environmental performance record of his business shows that he is walking the walk.   Ellenbogen is the President of Allied Converters  that manufactures food packaging.  His facility is about 55,000 square feet and does a lot of manufacturing with heat to seal the bags, all electrically driven.  The facility has solar panels and uses co-generation.  He explains:

In 2008, the average energy cost per square foot for a commercial facility in  Westchester was $1.80.  We were at 16% of that 12 years later and even with the increases, we are at 62% of that 14 years later.  That has been done while having a carbon footprint 30% – 40% lower than the utility system.  The $1.80 per foot  also included commercial office space and our operation is far more energy intensive than an office.  We use energy extremely efficiently and as a result, our bills are much lower than everyone else. 

NY State Energy Storage Report

On December 28, 2022 the New York Department of Public Service and New York State Energy Research and Development Authority released New York’s 6 GW Energy Storage Roadmap: Policy Options for Continued Growth in Energy Storage (Roadmap Report).  I did a couple of posts (here and here) on the Roadmap Report that concentrated on the costs.  Ellenbogen’s analysis fills in another part of the story.  His lightly edited description of the feasibility follows.

This is another document of such questionable quality that had I presented it to my superiors when I worked for Bell Labs and asked them to implement a multi-billion dollar project based upon it, they first would have rolled on the floor laughing thinking it was a joke, and then when they realized that I was serious,  they would have promptly terminated me.   No sane entity would embark on a project based upon such questionable parameters as are shown in this document.  This is not science or engineering.  This is politics disguised under a veneer of technical terms designed to delude the public that won’t take the time to read its 104 pages.  The fact that this policy is being pursued based upon documents such as this is borderline criminal  (And maybe not so borderline.  Just plain criminal).

Note that the page numbers I list are the pages of the pdf and not the document page numbers to enable easy searching of the document using Acrobat.

We can start with the fantasy on page 31 in Figure 5 (Also duplicated in the analysis in Appendix A) that immediately makes the entire document questionable.  It has all of the storage being charged by renewable energy by 2040 which will be impossible based upon NY State’s rate of renewable installation and the rate at which loads are being mandated to be added to the system.  (See below.  There is no fossil fuel generation even listed and it doesn’t list the composition of the “Imports”.  If they are like California’s imports, they will be coal generation.  Very environmentally friendly.)  Germany has been doing this for 32 years and has reached a 34% carbon free system with very few EV’s on the road.  While NY State is starting at 41% carbon free because of Niagara Falls and its upstate nuclear plants, the new renewables are not even going to offset the added load that has been mandated by state policy starting in 2024 and going into overdrive in 2030 and 2035 for EV’s and Heat Pumps, let alone replace all of the fossil fuel generation.  2040 is only 17 years away.  By 2050, the upstate nuclear plants will be 75 years old and nearing the end of their useful lifespan.  What will replace them?

Also, why are they using shoulder months in the analysis?  What will happen in July, August, January, and February when the electric load peaks?  That is what has to be analyzed as that is the worst-case scenario and is when the system will be most likely to fail.  The most likely reason for that is that the numbers and graphs looked so bad for those months, even in fantasy land, that they couldn’t be displayed for what they would show.

If you look at the following graph (link), the right-hand column documents the new renewables that will be available to offset the loads that they will be adding and it is clearly insufficient even if only 30% of the vehicle fleet is electrified and 10% of the buildings. 

Instead of Figure 5, the reality will be closer to Figure 5d below, produced by Cornell University and the National Renewable Energy Laboratory,  which show the batteries being charged from fossil fuels and 15% to 20% of that energy being lost because of charge/discharge losses, which is actually going to increase NY State’s carbon footprint.  The storage losses are acknowledged in the Roadmap Reprt document on page 99 where it says that the battery owner will have to buy 1.15 MWh in order to sell 1.0 MWH, implying a 15% energy loss.   

If that isn’t bad enough, on page 89 the Energy Roadmpa says, 

Customer load shifting can provide many of the same flexibility attributes as battery storage, by enabling reductions in peak demand, and shifting demand to times of high renewable output. As a result, there are direct impacts of lower or higher amounts of end use flexibility on the economics of battery storage. In  the base case, 12.5% of the light duty EV charging load is assumed to be flexible by 2030, increasing to 25% by 2050. In addition, 50% of the hydrogen required economy-wide is assumed to be generated via electrolysis within New York, and this electrolysis load is assumed to be highly flexible as well to make the most of excess renewable energy when it exists.

As clearly documented, WHAT EXCESS?  What are these people looking at?  THIS DOCUMENT IS NOT BASED UPON REALITY!!!

Further, Hydrogen electrolysis loses 20% of the energy when Hydrogen is generated from the water and then about 60% of what is remaining is lost during combustion for a total energy loss approaching 70%. That’s not a great tradeoff when you don’t have enough energy to  start with.

For some reason the filed report on the NYS DPS DMM site for Case 18-E-0130 – In the Matter of Energy Storage Deployment Program includes a cover letter.  That letter lists the storage capacity as a power value and not as an energy value.  The title of the cover letter is “Re: Case 18-E-0130 – In the Matter of Energy Storage Deployment Program” and then at the top of the next page the cover page of the document says New York’s 6 GW Energy Storage Roadmap:  Policy Options for Continued Growth in Energy Storage  however, Gigawatts (GW) are Power, not Energy.  While some may think that this is nitpicking, it isn’t.  Engineering students can fail tests over incorrect units.  All of the energy storage targets are listed as power, not energy.  The system runs on energy and with an intermittent renewable driven system, the storage duration is critical.  Nowhere will anyone be able to determine how long the storage will support the system except  on page 15 and those figures should be included with the question, “Are you kidding me?” next to it.  The explanation is below.

In fact, if anyone searches the entire pdf for “WH” to find all of the references to energy that are contained in it (Gigawatt Hours – GWh, Megawatt Hours – MWh, and Kilowatt Hours – KWh) the vast majority are devoted to information about rebates and costs and not what will be available to run the system.  Most of what was found were “What”, “Why”, “Which”, but very little about system capacity except in a couple of places.  On page 15 the Energy Roadmap discusses the cancellation of 20% of the battery projects:

While the program initially procured 580 MW and 1,654 MWh of energy storage, cancellations have brought these numbers down to 480 MW and 1,314 MWh.

Keep in mind that the pre-cancellation figure of  1654 MWh of battery storage with a 580 MW Power Capacity is less than THREE hours of storage for the bargain price of $193 million in state incentives.  During a heat wave, peaker plants can run for days.  On page 25 of the pdf, it states that many of the peakers only run 5% to 10% of the year,  which equates to 440 – 880 hours annually, however much of that time is contiguous during periods of high load and is far longer than 3 hours so how can a 3 Hour battery keep the system running if replacing a peaker plant?

On page 27, the Energy Roadmap discusses the possibility of using EV’s to offset a shortage of storage.   You can tell that whoever wrote this lives in Albany and not downstate where  a large number of people live in apartments.  Vehicles parked on streets are not going to be able to discharge to support the system in times of need.  Are they planning on putting a bidirectional charger on every parking spot in every downstate garage and on every parking spot on the street?    What will that cost and who will install it?   In New Rochelle, it took several months to install about ten internet kiosks with multiple street cuts to house data cables.  How long will it take to install thousands of chargers supported by far larger megawatt power cables to enable vehicle charging?  Also, having driven a Tesla for nearly six years now, I can safely say that trying to run a domicile for any extended period with the car’s battery and still having energy remaining to commute are mutually exclusive.  Again, times of peak load can run for days during the summer.  Winter peak load durationss will be similar in NY State during future winters when large numbers of heat pumps are installed.

On page 40 of the pdf, under 4.3 “Barriers To Energy Storage”, it says:  

As highlighted in other sections of this Roadmap, one of the most critical barriers to energy storage projects relates to the uncertain and insufficient nature of the revenue available through existing markets and tariffs, particularly capacity revenue. Retail or distribution-level projects, participating in certain regions through VDER, provide investors with a more certain revenue stream; however, these projects are still difficult to underwrite given the variable nature of both capacity and energy prices. 

On page 9, it says:  

Over the past year, supply chain constraints, material price increases, and increased competition for battery cells have driven up the cost of energy storage technologies, particularly lithium-ion batteries. Many of the drivers of cost increases are expected to persist until at least 2025. These cost increases may impact the cost of any new programs designed to procure storage to be installed by 2030.  

How they can predict the cost of commodities out past five years is beyond me, but it is safe to say that with everyone trying to install storage and at least nine states mandating electric vehicles, the demand is only going to make the price of storage go up and the materials will be scarce.  That doesn’t require a Crystal Ball, only a small degree of common sense.

The document states that the residential incentive is $ 250/KWh as seen on page 17, however if you look on page 37 it says:

Since July 2021, prices for lithium carbonate, a key ingredient of lithium-ion batteries, have increased 500%. Among projects awarded NYSERDA incentives, average total installed costs for non-residential, retail projects averaged $567/kWh for installations occurring in 2022 and 2023, up from $464/kWh for installations in 2020 and 2021, an over 20% increase in total costs.  This is consistent with recent industry reports that indicate near-term increases in storage costs.

That cost increase helps to explain the battery project cancellations.

Then on page 104, it says “Stakeholders across all segments that were surveyed or engaged with brought up increases in lithium-ion battery pricing over the course of 2021 and 2022 as a fundamental challenge to deploying storage and the development of the storage market going forward.”

On page 94 it does imply that 1000 hours of storage will be needed.   “With seasonal storage (1000+ hours), the availability of a specific resource during critical weeks – or in between multiple critical weeks in a season matters less; instead, the cheapest form of energy”

Coincidentally, that is almost the same time frame (40 days) that I showed on the graph above that was created about 5 weeks ago.  However, at the current average national cost of utility grade storage of $283 per KWh, 4 GW of storage that will last for 960 hours will cost over $1 TRILLION.  The 6 GW will cost over $1.5 TRILLION.  But with the escalating costs of Lithium, that figure could easily reach $ 3 TRILLION.  That figure is fourteen times the entire NY State budget for 2023.  The Inflation Reduction Act had $387 billion allocated for renewable energy projects for the entire United States.  That will just be the cost of the storage, independent of the cost of the renewable generation needed to charge it.


So  basically what they are saying is, “We aren’t sure how the economics of this is going to work but we are going to mandate its installation in lieu of fossil fuel plants, with an unknown price structure, increased energy losses when there already isn’t enough energy to support the system, insufficient capacity to replace the peaker plants that we are trying to close, rapidly escalating costs for the battery storage that already is not affordable and are only going to get more expensive in the future, and cross our fingers that this won’t make it impossible to complete the installation of 6 GW of energy storage.  However, in the interim, we will have shuttered the energy plants that we have for ones that we can’t afford to install.”

They are pushing forward with it anyway when it is doomed to fail.  This  goes way beyond money.   The inevitable failure is going to cost lives and they don’t even seem to care.  I was able to produce this analysis in hours.  They’ve had years to ponder these issues.  This is insanity and again, it is borderline criminal.

If they gave a damn, they would say, “Wait a minute.  This isn’t going to work.  We’re going to kill a bunch of people.  Maybe we should rethink this.”  Unfortunately, they aren’t doing that.   

Caiazza Closing Thoughts

New York State’s GHG emissions are less than one half a percent of global emissions.  Global GHG emissions have been increasing on average by more than one half a percent per year since 1990.  That does not mean that we should not do something but it surely calls into question why these limitations of the proposed plans are being ignored.  There is time to make sure the net-zero transition does not do more harm than good. I fully agree with Ellenbogen’s frustration that fundamental feasibility questions are not being addressed and his conclusion that this is insanity.

Arctic Blast Foreshadows Problems with Climate Act Renewable Future

This past Friday and Saturday (February 3-4 2023) there was a brief shot intensely cold air to the Northeast US.  This post includes a couple of descriptions of the implications of this weather event relative to the Climate Leadership and Community Protection Act  (Climate Act) and I present some data describing the event.

This is another article about the Climate Act implementation plan that I have written because I believe the ambitions for a zero-emissions economy embodied in the Climate Act outstrip available renewable technology such that the net-zero transition will do more harm than good.  The opinions expressed in this post do not reflect the position of any of my previous employers or any other company I have been associated with, these comments are mine alone.

I am Thankful – Mark Stevens

Mark is a regular reader at this blog and has contributed several recent items for posting.  He is a retired science and technology teacher from Long Island.  His email to me this weekend is a perfect introduction to the issues raised by this weather event.

It was 3 degrees F Saturday morning with a wind chill of -3 degrees.  All night the north wind raged, rattling “sealed” windows and doors but still blowing frigid air through them. I did everything I could: raise the boiler’s temperature, cover the big expanse of glass on the patio doors windows, pull the shades.  I even added an electric heater in the room my tropical parrot resides so he doesn’t get a fatal pneumonia.

The possibility of a power failure crossed my mind with the overhead wires, high winds, many surrounding trees, and almost monthly power interruptions in the past.  It would be an absolutely worst-case scenario if the power went out tonight. Frozen pipes next? I have a backup generator but the thought of going out in the howling cold night, fueling it, hooking it up, starting it, and monitoring the systems wasn’t that appealing.

But LIPA’s tree trimming maintenance and generation/distribution system upkeep allowed the power to stay on through the night and into the next day as I write this. We’re cozy, comfortable and safe.  This kind of cold can kill.

I’m thankful we have a reliable, cost-effective electrical generation and distribution system.  I’m thankful I have a natural gas-fired boiler that works 24/7 keeping me and my family safe and alive.  I am thankful that I don’t rely on intermittent, expensive wind and solar generation as electricity sources that can fail at any time leaving me without power.  I’m grateful I don’t have to rely on “backup” battery power that is grossly inadequate, expensive, highly polluting to manufacture and can cause a non-extinguishable toxic gas fire. I pray it does not change.

What’s Keeping the Heat On – James Hanley

James is a Fellow at the Empire Center.  His post yesterday is a great overview of the problem facing New York as it continues the implementation of the Climate Act.

As another Arctic blast hits the Northeast and temperatures plunge, more energy is needed to keep New Yorkers warm.   Where is that energy coming from? 

A lot of it comes from natural gas, but there’s a big supply problem. Because of the state’s ban on fracking and its refusal to allow new and upgraded natural gas infrastructure, not enough gas can get to power plants to generate the electricity needed to keep the lights and heat on in everyone’s houses during times of extreme demand. 

What gas is available gets bid up to eye-wateringly high prices. It’s hard to speak meaningfully of an average price for natural gas because the market is volatile, but the 2022 high price in Pennsylvania was $12.95 per million British thermal units (mmbtu). According to one energy industry source, during last Christmas’s cold snap, the price in New York hit $100 per mmbtu. 

That translated into an electricity price of nearly 90 cents per kilowatt hour, compared to the average New York price of 19 cents. 

That assumes the power plant can even get the gas it needs to operate. With such severe gas shortages, some natural gas-fired plants had to shut down for lack of fuel. What gets burned to take their place – fuel oil – is not only expensive, but also much dirtier and producing more carbon dioxide than natural gas. 

So, ironically, because New York has limited the supply of the much cleaner burning natural gas in order to prevent pollution and CO2, the power industry has no choice at times but to spew more pollution into disadvantaged communities and add more carbon to the atmosphere. 

The hope is that renewables will one day suffice to supply the electricity we need to heat our homes on a day like this. That hope is irresponsible, because wind and solar aren’t reliable and there is no available “clean” backup power source. 

Below is a graph from the New York Independent System Operator’s (NYISO) real-time dashboard, showing fuel use on February 2 into the early hours of February 3. On what was otherwise a reasonably good day for wind power (the light green line), we can see it declining in the early hours of February 3 as the cold front moved in, while the use of dual fuel generators (the top line), which can burn fuel oil, dramatically increased. Building more wind turbines has limited effect – as the wind drops across the state, all the turbines decrease in output. 

NYISO has repeatedly warned – and the Climate Action Council’s Scoping Plan admits – that wind and solar will not be sufficient. New York will need between 25 and 45 gigawatts of dispatchable power – power that unlike wind and sun, but like natural gas, fuel oil, and hydro, can be turned on and off at will. 

To comply with the Climate Leadership and Community Protection Act (CLCPA), these sources are supposed to be emissions free, leading NYISO to coin the ugly acronym DEFRs – dispatchable emissions-free resources. But they coined that term because they can’t identify any source that meets that standard and is currently available at utility scale and a commercially competitive price. 

This means that for the foreseeable future, fossil fuels will be the only proven source of dispatchable backup to keep the heat and lights on during weather that is killingly cold. Since New York no longer has any coal plants, that can be oil – which is more polluting and has higher carbon content – or natural gas. 

The CLCPA has a clear goal of eliminating all greenhouse gas emitting power production by 2040, which would mean shutting down all natural gas-fired power plants. But it also provides a path for keeping open those plants that are necessary to ensure a reliable electrical supply. That path, however, faces considerable political opposition. 

New York will soon be forced to make a choice: plunging forward with shutting down natural gas-fired power plants, risking rolling blackouts during extreme cold, or moving forward more slowly on its emissions goals, but keeping the heat on. There is no third way.

The Numbers

The past two days were ideally suited to staying inside.  I am a numbers guy so I spent time the last several days watching the weather and the electric system using two different resources.  The go to resource for weather observations in New York is the NYS Mesonet At UAlbany.  I watched the arctic air come into the region and then tracked the event over time.  The NYISO Real-Time Dashboard is a fascinating link into the New York electricity market.  I suspected correctly that this weather would cause a spike in electric load and I could see that play out over the period.

The weather data presented here is all from the NYS Mesonet at the University of Albany.  The following graph lists the last seven days of temperature, dew point temperature, and solar irradiance data at Elbridge, NY which is near my home.  Note that at the time I write this it is February 5 at 8:00 AM and that corresponds to 05/13 or 1300 universal coordinated time or Greenwich mean time, the standard for meteorological observations.  On the night of February 2 the temperature (red) was around 38oF about 7:00 PM EST or 0000 UTC.  Then the front came through and the temperature plunged overnight and during the day before briefly leveling out a few degrees above zero until nightfall when it dropped down to 7 or so below.

The next graph is for the same time period but shows the wind speed, wind gusts, and pressure.  Frontal passage was accompanied with a dip in the station pressure.  The pressure gradient was strong for most of the period so winds were steady slightly above 10 mph with gusts peaking at 38 mph.

The NYISO Real-Time Dashboard has two relevant graphical displays:  the load and real-time fuel mix. The following graph shows the actual and forecast New York total load on February 3-4 (all times are EST).  It is noteworthy that the actual loads on both days were  significantly higher than forecast loads.  The load peaked on 2/3 at 6:50 PM at 23,447 MW and at 6:10 PM on 2/4 at 21,990 MW. 

The NYISO 2022 Load and Capacity Data report winter peak demand projections are all greater than the observed peak loads so this should not have been a demand response problem with the existing fleet.

The real-time fuel mix data shows how the existing fleet met the peak loads during this weather event.  The following table lists the daily statistics for the different fuel types.  The fuel-mix categories are Nuclear; Hydro, including pumped storage; Dual Fuel, units that burn natural gas and other fossil fuels; Natural Gas only; Other Fossil Fuels, units that burn oil only; Other Renewables are facilities that produce power from solar, energy storage resources, methane, refuse or wood; and Wind (at this time exclusively land-based wind).

The graphs show how important the fossil fuel units are to keeping the lights on.  One notable feature of the fuel type data on 2/3 is that the wind generation was not very high even though winds across the state were quite high.  I believe this is because wind turbines don’t provide optimal power if the winds are too light or too strong.  The strong winds on this date apparently affected the wind production so even on a windy day New York’s land based wind provided only 65% of the maximum potential capability.

On 2/4/2023 the wind resource was affected by light winds.  On this date New York’s land based wind provided only 32% of the maximum potential capability.


Stevens explains how important it is for our safety and well-being to have fossil fuels available during extremely cold weather.  Hanley showed that natural gas played an important role keeping the lights on during this arctic blast and described some of the uncertainty associated with the planned net-zero transition.  My contribution was to provide more documentation for the weather, resulting electric load peak, and the contribution of different fuels to meeting that peak.  I am going to follow up on this post with a deeper dive into the resource availability and implications to the Scoping Plan recommendations for generating resource allocations.

Hanley’s conclusion is spot on:

New York will soon be forced to make a choice: plunging forward with shutting down natural gas-fired power plants, risking rolling blackouts during extreme cold, or moving forward more slowly on its emissions goals, but keeping the heat on. There is no third way.

Guest Post: South Shore Long Island Whale Die Off

This is a guest post by Mark Stevens, a regular reader at this blog.  Mark is a retired science and technology teacher from Long Island.  I have been meaning to do a post on whales and the offshore wind industry so this was timely.

What’s Going On

The NY Post reported a 7th dead whale washed up on the Jersey shore. A humpback washed up on the Amagansett shore in December. Eight dead whales in two months?  Moreover, David Wojick recently reported that on January 18, 2023 there was a NOAA fisheries media teleconference that noted:

Since January 2016, NOAA Fisheries has been monitoring an Unusual Mortality Event for humpback whales with elevated strandings along the entire East Coast. There are currently 178 humpback whales included in the unusual mortality event.  Partial or full necropsy examinations were conducted on approximately half of the whales. Of the whales examined, about 40% had evidence of human interaction, either ship strike or entanglement. And to date, no whale mortality has been attributed to offshore wind activities.

The transcript makes for fascinating reading.  The Fisheries spokespersons went to great lengths to make the point that no whale mortalities have been directly linked to offshore wind development.  But there were notable conditions in those statements: “We do not have evidence that would support the connection between the survey work and these recent stranding events or any stranding events in the last several years.”  The other key condition is that the offshore wind development is doing survey work now and not construction.  The open question is whether or not offshore wind development could kill whales.

Bloomberg reports that planned wind projects off the New England coast threaten to harm the region’s dwindling population of endangered right whales, according to a US government marine scientist.  The warning from a top National Oceanic and Atmospheric Administration official, obtained by Bloomberg under a Freedom of Information Act request, underscores the potential legal and environmental perils of offshore wind development along the coast.  Both initial construction of wind projects and decades of expected operation threaten to imperil right whales in southern New England waters, Sean Hayes, chief of the protected species branch at NOAA’s National Northeast Fisheries Science Center, said in a May 13 letter to Interior Department officials.  The department is weighing at least 10 proposals to install wind turbines in shallow Atlantic waters — projects key to fulfilling Biden’s 2030 goal.

The NOAA fisheries media teleconference claimed that survey work had not been linked to  whale strandings.  Surveys entail prolonged use of “machine gun sonar” emits an incredibly loud noise several times a second, often for hours at a time, as the ship slowly maps the sea floor.Mapping often takes many days to complete. A blaster can log hundreds of miles surveying a 10-by-10 mile site.

There are lots of ways this sonar blasting might cause whales to die. Simply fleeing the incredible noise could cause ship strikes or fish gear entanglements, the two leading causes of whale deaths. Or the whales could be deafened, increasing their chances of being struck by a ship later on. Direct bleeding injury, like getting their ears damaged, is another known risk, possibly leading to death from infection. So there can be a big time difference between blasting and death.  Sonar blasting in one place could easily lead to multiple whale deaths hundreds of miles away. If one of these blasters suddenly goes off near a group of whales they might go off in different directions, then slowly die.  It is not guaranteed that the dead whales will wash up on shore.

The NOAA fisheries media teleconference did not address construction impacts.  Sound travels 5 times faster in water and humpback whale sounds can travel thousands of miles according to Scientific American.  Pile driving the hundreds of enormous monopiles that hold up the turbine towers and blades will be far louder than the sonic blasters, especially with eight sites going at once. These construction sites range from Virginia to Massachusetts, with a concentration off New Jersey and Long Island.  This is shown to cause whale mortality.

The impetus for the The NOAA fisheries media teleconference was related to humpback whales strandings. However, some of the dead whales off New Jersey are endangered sperm whales. And there are the severely endangered North Atlantic Right Whales throughout the area where offshore wind developments are planned.

Offshore Wind and the Climate Act

New York’s Climate Leadership and Community Protection Act (Climate Act) established a “Net Zero” target (85% reduction and 15% offset of emissions) by 2050. The Climate Act requires that by 2030, 70% of electricity will be generated from renewable energy sources such as solar and wind and calls for the development of 9,000 megawatts of offshore wind energy by 2035.

According to the New York State Offshore Wind Overview five projects have been procured: South Fork (132 MW), Empire Wind  1&2 (816 MW and 1,260 MW), Sunrise Wind (924 MW), and Beacon Wind,230 MW).  Unfortunately, the websites do not provide consistent information but the best guess number of turbines is 316 for a total of 4,362 MW.  At that rate, the 9,000 MW target will require 652 turbines with capacities between 11 and 15 MW.  On January 26, 2023 bids were due for another round of Climate Act offshore wind development.

Is it time to re-think offshore wind?

In order to do the offshore wind development site surveys an incidental harassment authorization is required.  The first  fact is that the huge 2016 jump in annual humpback mortality coincides with the huge jump in NOAA Incidental Harassment Authorizations.  The second fact is that this is just the start of whale harassment when hundreds of enormous monopiles are driven into the seabed for the massive deployment of offshore wind.  When construction gets into full swing there will be multiple pile drivers hammering away which can only result in impacts beyond incidental harassment.

In addition to the hundreds of bird strikes including bald eagles and others, wind turbines are massive killing machines here and around the world.  And the fact that they produce energy about ¼ of their nameplate capacity, cost hundreds of billions of dollars with huge taxpayer subsidies, are intermittent and still need fossil generation backup when the wind stops, require 10s of thousands of acres, have shortened life in the harsh marine environment; require more steel, concrete, copper, and materials than conventional generation of the same output; have monstrous fiberglass blades which are not recyclable, why are we blindly building them?  In addition, most wind projects are built by foreign companies. Do we want billions of ratepayer dollars and taxpayer subsidies going overseas?

According to a study by the Center For Management Analysis of CW Post/LIU, Dr. Matt Cordero determined repowering the Northport Power Station alone with state-of-the-art technology will produce 3500+ MW (more than Empire Wind), cut emissions over 90%, cost less than Empire, use fewer materials, use a fraction of the area that ALREADY EXISTS with a power station and in-place infrastructure, will have zero bird strikes and whale deaths, provide tax benefits for the community, will last decades longer and is on call 24/7 vs. intermittent (20% of the time) wind. 

Furthermore, intermittent wind and solar need massive battery backup and storage with huge costs, land requirements, massive pollution and greenhouse gas emissions for ore extraction and fabrication, and pose a deadly hazard to the region if it catches on an unextinguishable fire that emits deadly gasses.

Emission reduction by NYS will have an undetectable effect on global emissions, especially with China, Russia, India and others building dozens of coal power plants.  They will have reliable, life-saving, cost-effective electricity generation.  States with a large portion of renewables like California, Texas, North Carolina have high rates, power failures, rolling blackouts and a restricted weather operating range, and they IMPORT reliable power from other states, thus relocating emissions to surrounding states. Tesla and others left California for those reasons.  Are they really cutting emissions?

Finally,   the European Union, especially Germany and the UK have shuttered nuclear and fossil generation, relying on unreliable wind and solar sources.  Costs are so high, people must decide whether to buy electric heat or food, and  industries are leaving for other countries with cheaper and more reliable electricity, resulting in unemployment, poverty and economic collapse.

We currently have a reliable, cost-effective generation mix of fossil, wind, solar, hydro and nuclear.  New York State must seriously rethink replacing that generation with intermittent wind and solar.  Our survival and economy depend on it.

New York Energy Storage Roadmap – Cost Projections Part 2

On December 28, 2022, the New York State Energy Research & Development Authority (NYSERDA) and the New York State Department of Public Service (DPS) filed New York’s 6 GW Energy Storage Roadmap (Roadmap) to the Public Service Commission (PSC) for consideration.  I previously gave an overview of the Roadmap and looked at the way the costs were projected.  In this post I give my estimate of the costs.

Everyone wants to do right by the environment to the extent that they can afford to and not be unduly burdened by the effects of environmental policies.  I submitted comments on the Climate Act implementation plan and have written over 270 articles about New York’s net-zero transition because I believe the ambitions for a zero-emissions economy embodied in the Climate Act outstrip available renewable technology such that the net-zero transition will do more harm than good.  The opinions expressed in this post do not reflect the position of any of my previous employers or any other company I have been associated with, these comments are mine alone.

New York Energy Storage Plan

The NYSERDA Energy Storage in New York web page gives an overview of New York’s plan:

In 2019, New York passed the nation-leading Climate Leadership and Community Protection Act (Climate Act), which codified some of the most aggressive energy and climate goals in the country.

6,000 MW of Solar by 2025

70% Renewable Energy by 2030

9,000 MW of Offshore Wind by 2035

100% Carbon-free Electricity by 2040

85% Reduction in GHG Emissions from 1990 levels by 2050

3,000 MW of Energy Storage by 2030, further increased to 6,000 MW of Energy Storage by 2030 by Governor Kathy Hochul

In my previous post I pointed out that the press release for the Roadmap claimed that “the roadmap will support a buildout of storage deployments estimated to reduce projected future statewide electric system costs by nearly $2 billion”.  The state’s modeling predicts that it will cost $0.46 per month per electricity bill and the trade press has jumped on that cost as less than the cost of a slice of pizza.

I showed that Roadmap costs are misleadingly presented relative to incremental revenues: “For the proposed bulk storage procurement program, program costs are calculated as the incremental revenue, on top of revenue that storage assets can realize through commercial operation in the existing energy markets, that would allow such assets to reach their cost of capital.”  If the state were to be open and transparent, the total expected capital costs, the revenue costs, and how they expect energy storage to get paid would be presented so that readers could understand the incremental revenue.  I have come to believe that the obfuscation of the actual costs is deliberate because the numbers are so large that the public backlash would be immense.

Cost Estimates

I have written in the past that every aspect of the net-zero transition that I have evaluated has turned out to be more complicated, uncertain, and nuanced than has been portrayed by the proponents of net-zero transitions.  This calculation is no different.  On the face of it you just figure out the capacity (MW) needed or the energy generation (MWh) needed and the multiply those values by a published cost estimate. 

I am not going to discuss all the ambiguities I tried to reconcile but will give an example of one.  In order to estimate the electric resources needed to power the zero-emissions electric grid in 2040 sophisticated modeling is required.  The New York State Energy Research & Development Authority (NYSERDA) and its consultant provided that evaluation for the Scoping Plan for the net-zero transition plan required by New York’s Climate Leadership and Community Protection Act (Climate Act).   The New York Independent System Operator did modeling for its 2021-2040 System & Resource Outlook evaluation.  I looked at five of the scenarios they modeled: NYISO Outlook Scenario 1: Industry data and forecasts, NYISO Outlook Scenario 2: Assumptions aligned with Integration Analysis, Integration Analysis Scenario 2: Strategic Use of Low-Carbon Fuels, Integration Analysis Scenario 3: Accelerated Transition from Combustion, Integration Analysis Scenario 4: Beyond 85% Reduction

There are substantial differences in the methodology used for the energy storage estimates between the two approaches.  Table 1 lists the capacity (MW) and generation (GWhr) projections for the present and 2040 for the five scenarios.  Note that the storage capacity estimates are roughly the same but the generation estimates are different.  The NYISO generation is at least 13,414 GWhr in 2040 but the Integration Analsis generation is negative, so the methodologies are different.  Energy storage generation can represent two different things: the amount of electricity stored say over a year or the amount of electricity that can be stored all at once, the storage capacity.

Table 1: NYISO Outlook Study Scenarios and Integration Analysis Mitigation Scenarios

I believe that both analyses use total stored electricity for their energy storage estimates.  David Wojick recently used the storage capacity approach to estimate energy storage costs.  His approach simply takes:

  • a reasonable period of no wind and solar, say 3 days or 72 hours, and
  • a reasonable average demand on renewables over that period, say 35,000 MW, and
  • multiply them to get 2,520,000 MWh of required storage
  • which at $700,000 per MWh equals $1,764,000,000,000

Given the issues with the energy storage generation different interpretation, I chose to use Energy Information Administration overnight capital costs (2021$/kW) in the comments I submitted on the Draft Scoping Plan to make a cost estimate.  This approach does not include operating and maintenance (O&M) costs, the expected lifetime of the energy storage devices, and how the lifetime would vary depending on how it is used.  My estimate of the overnight cost to develop the resources needed to transition to a zero-emissions electric system in 2040 are generally consistent with the Scoping Plan Appendix G Figure 48 net present value of system expenditures.  Table 2 lists those costs for all five scenarios.  This approach estimates a cost three orders of magnitude less than the costs projected by Wojick.  The big difference is that both NYISO and NYSERDA include a zero-carbon firm resource or dispatchable emissions-free resource (DEFR) that can satisfy the need for extended periods of high load and low renewable energy resource availability thereby reducing the energy storage needed.

The NYISO 2021-2040 System Resource Outlook explained that to achieve a zero-emissions grid, DEFRs must be developed and deployed throughout New York.  The following Figure 38 from the Roadmap illustrates the problem.  The difference between cost estimates emphasizes why this resource is needed.  The ultimate problem of any electric system that relies on intermittent wind and solar is that there are periods when they are not available.  It turns out that the weather systems that cause light winds are large and affect all of New York at the same time and solar resources are lower in the winter when days are short and the sun is lower in the sky.  In other words, all the renewable resources in the state can go very low at the same time.  Just figuring out what the worst case of renewable resource availability is a major problem and both modeling groups agree that something besides batteries is needed.  The Outlook noted that “While essential to the grid of the future, such DEFR technologies are not commercially viable today” and went on to point that research and development efforts are needed to identify the most efficient and cost-effective technologies that can be deployed.  Needless to say, it is risky to depend on a resource that is not currently commercially viable that makes such a difference between costs.


The Hochul Administration claims that “the roadmap will support a buildout of storage deployments estimated to reduce projected future statewide electric system costs by nearly $2 billion”.  The key point is that nowhere does the Roadmap document total costs. The fair question is what are the projected future statewide electric system costs?  Moreover, I showed previously that Roadmap costs are presented relative to incremental revenues: “For the proposed bulk storage procurement program, program costs are calculated as the incremental revenue, on top of revenue that storage assets can realize through commercial operation in the existing energy markets, that would allow such assets to reach their cost of capital.”  It is impossible to check the validity of that statement without full disclosure of all these cost components.

This analysis compares future statewide electric system costs for energy storage.  The simplest approach estimates that energy storage necessary to provide electricity when wind and solar resources are unavailable could be as much as $1.7 trillion.  NYISO and NYSERDA used more sophisticated analyses to refine how much backup was needed.  The overnight capital costs for the batteries, and only the batteries, for five different scenarios ranges from $13 to $15 billion.  There are a host of other factors that could raise those estimates.  The approach used by NYSERDA and NYISO relies on DEFR technologies that increase the cost to provide backup when wind and solar resources are unavailable totals between billion $187 and $349 billion but provide massive savings relative to any approach that does not include that kind of resource.  It is clear that whatever approach is used, that the Hochul Administration claim of “savings” of $2 billion is insignificant relative to the total costs which are at least two orders of magnitude larger.


The Roadmap has been presented to the Citizens of New York as a sales spiel.  The public heard that the costs of energy storage were only $2 billion and that the cost to ratepayers would be less than the cost of a slice of pizza.  The costs that ratepayers will ultimately pay is much, much higher.  The shell game manipulation of costs demonstrates that the Hochul Administration goal is hide the expenditure of hundreds of billions of dollars under so many different programs and subsidies to make it intentionally impossible to capture the total costs to consumers.  The true “Total Cost” of the Climate Act will be hidden forever from the public by design. 

My thanks to David Wojick for his review and comments.  Any errors in this analysis are my responsibility.

Getting to 100%: Six strategiesfor the challenging last 10%

A recent paper, Getting to 100%: Six strategies for the challenging last 10%, provides a concise summary of six technologies that could be used for the Climate Leadership and Community Protection Act (Climate Act) legal mandate for New York State greenhouse gas emissions to meet the ambitious net-zero goal by 2050.  I continue to be amazed that the parties responsible for Climate Act implementation continue to ignore the risks associated with these aspirational technologies so this article summarizes this useful paper.

Everyone wants to do right by the environment to the extent that they can afford to and not be unduly burdened by the effects of environmental policies.  I submitted comments on the Climate Act implementation plan and have written extensively on New York’s net-zero transition because I believe the ambitions for a zero-emissions economy embodied in the Climate Act outstrip available renewable technology such that this supposed cure will be worse than the disease.  The opinions expressed in this post do not reflect the position of any of my previous employers or any other company I have been associated with, these comments are mine alone.


The implementation plan for New York’s Climate Act “Net Zero” target (85% reduction and 15% offset of emissions) by 2050 is underway.  The Climate Action Council has been working to develop plans to implement the Act.  Over the summer of 2021 the New York State Energy Research & Development Authority (NYSERDA) and its consultant Energy + Environmental Economics (E3) prepared an Integration Analysis to “estimate the economy-wide benefits, costs, and GHG emissions reductions associated with pathways that achieve the Climate Act GHG emission limits and carbon neutrality goal”.  Integration Analysis implementation strategies were incorporated into the Draft Scoping Plan when it was released at the end of 2021.  Since the end of the public comment period in early July 2022 the Climate Action Council has been addressing the comments received as part of the development of the Final Scoping Plan that is supposed to provide a guide for the net-zero transition.

I have previously written that the Climate Action Council has not confronted reliability issues raised by New York agencies responsible for keeping the lights on.  The first post (New York Climate Act: Is Anyone Listening to the Experts?) described the NYISO 2021-2030 Comprehensive Reliability Plan (CRP) report (appendices) released late last year.  The difficulties raised in the report are so large that I raised the question whether any leader in New York was listening to this expert opinion.  The second post (New York Climate Act: What the Experts are Saying Now) highlighted results shown in a draft presentation for the 2021-2040 System & Resource Outlook that all but admitted meeting the net-zero goals of the Climate Act are impossible on the mandated schedule.  Recently I wrote about the “For discussion purposes only” draft of the 2021-2040 System & Resource Outlook report described in the previous article. 

Challenges of a Zero-Emissions Electric Grid

It is generally recognized that as increasing amounts of intermittent wind and solar energy are added to the electric grid, unique issues arise as grid operators balance generation and load.  I maintain that the ultimate problem with a net-zero energy system is that increased electrification will markedly raise loads during weather conditions that cause peak loads but also can have low wind and solar resource availability.  A recent paper, Getting to 100%: Six strategies for the challenging last 10% (“Getting to 100% report”), describes approaches for providing power during peak conditions.  It describes the general peaking problem, how wind and solar will exacerbate the problem, and what the authors think is necessary to solve the future problem.

The authors from the National Renewable Energy Laboratory provided the following summary:

Meeting the last increment of demand always poses challenges, irrespective of whether the resources used to meet it are carbon free.  The challenges primarily stem from the infrequent utilization of assets deployed to meet high demand periods, which require very high revenue during those periods to recover capital costs.  Achieving 100% carbon-free electricity obviates the use of traditional fossil-fuel-based generation technologies, by themselves, to serve the last increment of demand—which we refer to as the ‘‘last 10%.’’ Here, we survey strategies for overcoming this last 10% challenge, including extending traditional carbon-free energy sources (e.g., wind and solar, other renewable energy, and nuclear), replacing fossil fuels with carbon-free fuels for combustion (e.g., hydrogen- and biomass-based fuels), developing carbon capture and carbon dioxide removal technologies, and deploying multiday demand-side resources. We qualitatively compare economic factors associated with the low-utilization condition and discuss unique challenges of each option to inform the complex assessments needed to identify a portfolio that could achieve carbon free electricity. Although many electricity systems are a long way from requiring these last 10% technologies, research and careful consideration are needed soon for the options to be available when electricity systems approach 90% carbon-free electricity.

The Getting to 100% paper describes six strategies that are summarized in the following table.  Note that the strategies are compared to an ideal solution.  Ideally, the solution for peak loads would have low capital expenses and low operating expense, low resource constraints, be technologically mature, have low environmental impacts, and work well with other resources.  Needless to say, no technology comes close to meeting those ideal conditions.  The authors note that: “Although existing studies generally highlight the same fundamental causes associated with the last 10% problem, there is a lack of consensus on the preferred strategies for meeting this challenge. This is not surprising, given the diversity of possible solutions and the speculative nature of their costs, given their early stage of development.”

Although I think the Getting to 100% paper is useful, I want to point out a few issues with it.  It is hardly unexpected that authors from the National Renewable Energy Laboratory appear to over-estimate the maturity and economics of wind and solar technologies.  Also note that in New York, the implementation plan calls for offshore wind capacity to be at least one third to over one half of the projected wind capacity but the report claimed that wind economic factors were low, capital costs low, operational expenses low and that wind has high technological maturity.  All true perhaps for land-based wind but certainly not true for off-shore wind. 

My biggest concern is that the analysis does not consider the ‘‘inverter challenge’’ as a major constraint.  Another report, “The challenges of achieving a 100% renewable electricity system in the United States”, explains that in the existing electrical system synchronous generators provide six services shown in the following table that provide system stability.  Wind and solar resources are asynchronous generators that do not provide those services.  Somebody has to provide them so this analysis that concentrates only on the levelized cost of energy that ignores those services under-estimates the cost and technological challenges to provide electricity to consumers.

The Getting to 100% paper explains that the biggest problem is making sure there is sufficient available capacity during all periods, even if that capacity is seldom used.  This problem is not new and exists in the existing system.  The paper notes:

The increase in costs associated with approaching 100% carbon-free electricity is a special case of the more general problem of meeting peak demand, which has always been part of the planning process for electric power systems. Variations in demand profiles and the existence of demand peaks are caused by variation in weather, end-use technology stock, and, ultimately, consumer preferences and behavior.

The Getting to 100% paper explains that there are differences between daily load and daily renewable energy (RE) generation over the year.  The following figure shows the seasonal patterns in the daily imbalance (daily load minus daily RE generation) for hypothetical high RE systems where about 90% of annual load is met by wind, solar, and other RE generation technologies for New York State. As noted previously the fundamental problem is that when the loads are the highest in the summer and winter, RE generation can be low.  In the spring and fall the RE resources are generally high but loads are low.   As the share of RE increases,” these aspects are increasingly accentuated”.  The paper makes the point that:

Eventually, with high enough VRE shares, the addition of new VRE capacity would offer very little benefit in reducing peaks in net load, while causing additional oversupply conditions where unusable VRE needs to be curtailed. The low capital utilization problem of meeting demand is exacerbated in high VRE systems. These issues shape the characteristics of a last 10% solution.

In the following I will address each strategy.

Variable renewable energy, transmission, and diurnal storage

This approach is “technologically conservative, as it relies only on technologies currently being deployed at gigawatt (GW) scale”. The seasonal mismatch problem is addressed by overbuilding wind and solar resources as well as adding more transmission capacity.  Diurnal storage is deployed to fill hourly supply gaps and excess wind and solar is curtailed during high-resource periods.  The authors claim: “Increasing oversupply during high-resource times decreases the amount of storage necessary to supply low-resource times.”  The authors admit that wind and solar “curtailment in such systems can reach 35%–50%”.  There is an associated problem.  As more wind and solar resources are added to minimize storage requirements, those additional resources markedly increase curtailment rates for all those resources.  

In order to address those issues, the authors claim that new developments could “make this approach more competitive” In particular: “Higher-capacity-factor system designs (low-windspeed and/or high-hub-height wind turbines; tracking PV arrays with high inverter-loading ratios preferentially increase output during low-resource periods, increasing VRE dispatchability”.  My impression however, is that those are tweaks and do not eliminate all issues.  The authors mention hybrid systems, “including concentrating solar power with thermal energy storage”, but neglect to mention that the Crescent Dunes Solar Energy Project that used this technology failed.  They also claim that “Increased long-distance transmission deployment (over distances larger than the extent of weather systems decreases curtailment, cost, and storage needs by exploiting the declining spatial correlation of VRE availability with increasing distance”.  Advocates of this approach never discuss just what distances are needed for it to work and just how it would work in practice.

According to Table 1 in the Getting to 100% paper, on the positive side the economic factors are relatively low cost and technological material is high.  The resource constraints are listed as medium but I think that is optimistic given the volume of these resources required.  Frequent claims of the low costs of wind and solar generation ignore the fact that the real cost that matters is the delivered cost.  When the costs to keep the lights on when the wind is not blowing at night are considered the low cost claims are wrong.

Other renewable energy

The study claims that “geothermal, hydropower, and biomass are renewable energy resources that do not rely on variable solar and wind resources and have higher capacity credit”. While the report claims that these resources can play an important role in a net-zero-emissions power system the fact is geothermal and hydro resources depend on certain physical site constraints so there is not a lot of potential availability in New York.  The main problem with biomass is that there are limits on how much could be produced and it is not enough to be a major contributor to the overall energy needs.  In New York there are members of the Climate Action Council that believe that zero-emissions means no combustion so there is an ideological constraint as well.

According to Table 1 in the Getting to 100% paper, on the positive side the technological material is high and some of the economic factors are favorable.  However, all the options have high resource constraints that limit the applicability of these options.

Nuclear and fossil with carbon capture

The study notes that “Nuclear and fossil with carbon capture and storage (CCS) are widely cited as potentially important resources in a decarbonized electricity system”.  There is no question that nuclear is the only emissions-free dispatchable resource that could be deployed in sufficient quantities to provide all needed baseload power.  The report notes that: ”The existing nuclear fleet comprises reactor designs with large nameplate capacities and designed to operate near their maximum output potential”, and that “Advanced nuclear reactor designs are typically smaller in scale and more flexible” .  Consequently, nuclear might be viable for the last 10% problem.  Alas New York, for example, on one hand worries about an existential threat of climate change but shuts down 2,000 MW of zero-emissions nuclear generation which suggests that this option is off the table.

The report notes that “Fossil CCS plants have yet to be deployed at scale, but some studies find significant deployment potential, including from retrofits of existing fossil fuel-fired Plants”.   The report sums up the pragmatic dilemma associated with this option:

Fossil CCS has a capture rate of less than 100%; therefore, some emission offsets are needed for fully net carbon-free electricity unless technology advancements, such as through oxy-combustion, can enable zero or near-zero emissions.  he role of fossil CCS could be impacted by how strictly the ‘‘100%’’ requirement is interpreted with respect to any remaining emissions that are not captured and emissions from upstream fuel extraction, including methane leakage.

There is another issue associated with CCS.  A fossil plant capturing CO2 has a derate of about one third because of the energy needed to run the equipment required to capture and compress the CO2 so that it can be transported and sequestered underground.  Finally, in order to safely store the CO2 particular geologic formations are required which limits where these facilities can be located.

According to Table 1 in the Getting to 100% paper, advanced nuclear has high capital expenses and moderate operating expenses; medium resource constraints, medium technological maturity, and security, supply chain, regulatory and cost uncertainties.  Fossil CCS has high capital expenses, medium operating expenses, medium resource constraints, low technological constraints, and issues with upstream emissions, CO2 transport and sequestration.

Seasonal storage

Seasonal storage refers to the use of electricity to produce a storable fuel that can be used for generation over extended periods of time later:

This group of technologies is not well defined, but it could include batteries with very low-cost electrolytes capable of longer-than-diurnal durations. Because of the requirement for very low-cost energy storage, most seasonal storage pathways focus on hydrogen, ammonia, and other hydrogen-derived fuels stored in geologic formations.

Hydrogen produced using electricity to split water (i.e., electrolytic hydrogen) is a form of storage because the energy it carries can be converted back to electricity.  Electrolytic hydrogen technology has been used at an industrial scale since the early 20th century. Although currently higher cost than hydrogen from natural gas reforming, electrolytic hydrogen production costs can be reduced if low- cost electricity, such as zero-cost otherwise-curtailed renewable energy, is used.

In the New York implementation plan the dispatchable emissions-free resource (DEFR) place holder is hydrogen produced using wind and solar.  In addition to the irrational ideological prohibition against combustion sources there are technological issues for New York.  The report notes that “current high-cost electrolyzers need to operate almost continuously to recover their capital expense” and that “Storage and transport costs would add to the delivered cost of hydrogen”. 

The New York ideologues plan is to use hydrogen in fuel cells, but the report notes:

Fuel cells have diverse applications, but their use for bulk power generation is currently limited. Given the range and scale of applications especially for transportation, substantial capital cost reductions for fuel cells are possible. With low capital costs for combustion turbines and future potential cost reductions for fuel cells, the economic case for hydrogen mainly hinges on lowering the cost of electrolytic hydrogen.

According to Table 1 in the Getting to 100% paper, it really is a stretch to say that there are any positive aspects for using hydrogen with combustion turbines or in fuel cells.  For hydrogen used in combustion turbines the report claims low capital expenses (apparently referring only to the combustion turbine but not including the generation of the hydrogen itself), medium operating expenses and resource constraints, and concerns about hydrogen storage and transport as well as competition for using hydrogen in other sectors.  For hydrogen used in fuel cells there is a potential for low capital expenses, high operating expenses, low resource constraints (apparently referring only to the fuel cell and not assuming that the hydrogen is generated with wind and solar resources), low technological maturity, and the same other considerations as hydrogen used in combustion turbines.

Carbon dioxide removal

The report describes carbon dioxide removal (CDR) strategies which are “dedicated efforts to reduce atmospheric CO2 levels.  In theory this can offset emissions from carbon-emitting power generation so that fossil-fired units can operate to fulfill the last 10% requirement. This is too far fetched to be credible in my opinion.

According to Table 1 in the Getting to 100% paper, there are no positive aspects of this technology except that there are low resource constraints for direct air capture and storage. 

Demand-side resources

Net-zero advocates are enamored with “smart planning” approaches that reduce load which reduces generating resource requirements.  The report notes that “Demand-side resources, also referred to as demand response or demand flexibility, have unique properties compared with the supply-side solutions”.  The report explains:

To a limited extent, they are already relied upon for grid planning and operations today. By reducing electricity consumption during times of system stress, these resources help avoid capital expenditures associated with new peaking capacity.  Through flexible scheduling or interruption of electricity consumption, they can also reduce operating costs or be used for important grid reliability services.

While there are indisputable advantages, I think that advocates lose track of the limitations.  There are demand-side programs in place today but the applications are limited.  Today’s programs limit reduction requests to rare instances of limited duration primarily to shave peak loads primarily by large industrial or commercial users. The problem is that applying demand-side options as a last 10% strategy for decarbonization “requires them to be reliably available over extended multi-day periods”. This means that they cannot be used for residential heating and cooling loads and electric vehicle charging. Moreover, the report notes that “Large-scale commercial or industrial customers can provide multi-day response, but extended interruptions would negatively impact these capital-intensive (non-power) applications”.  As a result, I don’t think this approach will provide adequate reductions when needed the most.

According to Table 1 in the Getting to 100% paper there are low capital expenses but there are uncertain opportunity costs.  The paper claims that resource constraints are uncertain and that the technological maturity is medium.  There are concerns about communications, control equipment and reliability.


An Inside Clean Energy article on the paper offers a summary from the climate advocacy side.  Of note is a plug for the 100% renewable option:

A growing segment of energy researchers say that the electricity system can run on 100 percent renewable energy, which would mean renewables and energy storage would provide the last 10 percent. This approach sees no good reason to build new nuclear plants or to use carbon capture systems on fossil fuel plants, citing high costs and a variety of other concerns.

The author admits that the myth of low-cost solar and wind resources does not take into account the resources needed for reliability during periods of peak demand:

At the same time, a sizable group of energy researchers maintain that nuclear and carbon capture are essential parts of getting to carbon-free electricity. This side has doubts about the ability of renewable sources to meet all needs, citing concerns about the availability of land and the intermittent nature of wind and solar. They note that wind and solar are not a low-cost option when taking into account the amounts of storage and power line capacity needed to make those resources reliable for meeting peak demand.

I find the author’s conclusion naïve:

Within all of this is something encouraging: Researchers and energy companies have figured out how to start the transition to 100 percent carbon-free electricity and they have a pretty good idea of what the in-between steps will look like. Now, they are beginning to dig deep on how this journey to a carbon-free grid may end.

Academic researchers are not accountable for reliability and have found a cash cow for funding.  No one is funding them to make a responsible estimate of future resources that does not fit the alarmist narrative.  In a de-regulated world energy companies are also not responsible for reliability and are toeing the line of the net-zero narrative.  New York’s organizations responsible for reliability are not as optimistic (here and here). New York’s Draft Scoping Plan presumes that the State can transition to net-zero without addressing reliability and affordability feasibility but the reality is that even this report suggests that substantive issues have to be addressed.


I think this is a biased report that is too optimistic for future projections.  Nonetheless, it does offer a concise summary of potential approaches to address the last 10% problem that is my ultimate concern.  With respect to New York’s implementation plans, if the concerns of the National Renewable Energy Laboratory staff are ignored in the Final Scoping Plan, then New York will surely have a catastrophic blackout with consequences far beyond any impacts that can be attributed to climate change.

More Reliability Concerns that Need to be Considered by the Climate Action Council

The Climate Leadership and Community Protection Act (Climate Act) has a legal mandate for New York State greenhouse gas emissions to meet the ambitious net-zero goal by 2050.  I have previously noted that there are members of the Climate Action Council who deny the challenge of the electric grid transition from existing sources to one dependent upon wind and solar resources.  This article describes a couple of recent articles that highlight transition issues.

Everyone wants to do right by the environment to the extent that they can afford to and not be unduly burdened by the effects of environmental policies.  I submitted comments on the Plan and have written extensively on implementation of New York’s response to that risk because I believe the ambitions for a zero-emissions economy embodied in the Climate Act outstrip available renewable technology such that this supposed cure will be worse than the disease.  The opinions expressed in this post do not reflect the position of any of my previous employers or any other company I have been associated with, these comments are mine alone.

Climate Act Background

The Climate Act establishes a “Net Zero” target (85% reduction and 15% offset of emissions) by 2050. The Climate Action Council is responsible for preparing the Scoping Plan that will “achieve the State’s bold clean energy and climate agenda”.  They were assisted by Advisory Panels who developed and presented strategies to the meet the goals to the Council.  Those strategies were used to develop the integration analysis prepared by the New York State Energy Research and Development Authority (NYSERDA) and its consultants that tried to quantify the impact of the strategies.  That material was used to write a Draft Scoping Plan that was released for public comment at the end of 2021. The Climate Action Council states that it will revise the Draft Scoping Plan based on comments and other expert input in 2022 with the goal to finalize the Scoping Plan by the end of the year.

In my comments on the Draft Scoping Plan I noted that the Plan and the Climate Action Council have downplayed the reliability risks of the Climate Act transition to renewables.  Equally troubling there are vocal members of the Climate Action Council that deny the existence of any implementation issues associated with a renewable energy resource dependent electric system.  At the May 26, 2022 Climate Action Council meeting, Paul Shepson Dean, School of Marine and Atmospheric Sciences at Stony Brook University claimed that the conversion cannot be unreliable at 23:39 of the recording.  Robert Howarth, Professor, Ecology and Environmental Biology at Cornell (starting at 32:52 of the recording) said: “Clearly one can run a 100% renewable grid with reliability”.   In this article, I describe a couple of recent articles that highlight some of the issues associated with this conversion that the academics overlook.

Renewable Energy Systems

I have prepared a page that documents the work of various authors that describe the complexities of the energy system and problems associated with over-reliance on intermittent wind and solar generating resources.  One of the resources is a series of posts at Climate Etc by Planning Engineer who posts under the pseudonym because he wanted to frankly share his personal views and not have them tied directly to his current employer.  Recently he posted an article entitled Will California “learn” to avoid Peak Rolling Blackouts? that provides a good overview of upcoming reliability issues.

The article presents a graph that shows recorded peaks and the projected 2022 value that caused issues earlier in September.  Then he explains that:

The most basic planning criteria is that a system should be able to survive the loss of the largest generating resource and the most critical transmission element during a peak load with no loss of load and no severe voltage declines or undamped system oscillations. Looking at the variability in load levels here, no particular challenges to planners are apparent. If “green” resources were capable of replacing traditional resources with minor adjustments, we would not see the problems we are seeing.

He goes on to explain why there was a problem.

Why is California challenged now and why might it continue to see challenges in the future?  Primarily because the focus on green energy is increasing the percentage of “green” intermittent resources. “Green” resources are not as dependable as traditional rotating machinery nor do they support the system as well. It is likely that these resources have been credited with more ability to provide capacity than is warranted, and when the rubber meets the road, they don’t perform as “expected”. Intermittent resources cause problems on both the generation side and the load side. Intermittent solar on the residential side serves to reduce load as seen by the Cal ISO. When solar is not performing well available load which is not displaced by solar on the residential side increases concurrent with solar reduction on the supply side.

If California were more honest about the capabilities of “green” intermittent resources planning would be enhanced. However, being honest about the capabilities of “green” resources would have consequences that some would find unacceptable. There has been a big push to make “green” options appear much more economic and capable than they are so that they will be more competitive. Subsidization of “green” resources by traditional uses occurs in many ways. In addition to crediting “green” resources above their dependable capability, others subsidies include directing costs associated with such additions to others. Being honest makes the “green” dream a much harder sell. Assuming that “green” resources work well saves other investment in the grid. This subterfuge tends to limit the cost increase that should be imposed by these resources, but does so at the cost of reliability. This tradeoff takes a while to see as we have built the electric grids to have very high levels of reliability at the bulk level. In the short term it looks like you are getting a cleaner, equally reliable system at a moderate cost increase. But as penetration levels increase, cost get higher and reliability gets much worse.

He points out that California policy makers are responsible for resource investment, resource allocations and how and when grid improvements are made to enhance reliability. Earlier in September there were reliability issues and extreme weather was blamed.  Obviously, the planning failed to account for weather but proper reliability planning has to account for the effects of extreme weather.  Planning Engineer points out that if “there truly was something unusual about the weather as driven by climate change, shouldn’t this have been anticipated by those responsible?” 

He concludes:

Ideally the power system represents the best balance between economics, reliability and public responsibility. California has reached a balance skewed by false expectations that “green” resources cannot meet. Creating a balance that looks at the true costs and reliability impacts of green resources should benefit electric users in California.

Ramping Up Renewables Can’t Provide Enough Heat Energy in Winter

Gail Tverberg writing at Our Finite World explains that one of the unappreciated benefits of fossil fuels is their ability to store energy that can be used to provide heat in the winter.  She notes that:

In some ways, the lack of availability of fuels for winter is a canary in the coal mine regarding future energy shortages. People have been concerned about oil shortages, but winter fuel shortages are, in many ways, just as bad. They can result in people “freezing in the dark.”

The article goes on to describe eight issues involved with winter energy use.  She points out that “batteries are suitable for fine-tuning the precise time during a 24-hour period solar electricity is used” but they cannot be scaled up to store solar energy from summer to winter.  There is no long duration energy storage resource available.

The article addresses hydro and wind energy resources in this context.  She argues that “ramping up hydro is not a solution to our problem of inadequate energy for heat in winter” and that “wind energy is not greatly better than hydro and solar, in terms of variability and poor timing of supply”.

She also lists five specific reasons that “when wind and solar are added to the grid, the challenges and costs become increasingly great”.  All of these concerns are concerning by themselves and the combination of problems directly contradicts the Climate Act narrative that there are no serious challenges to reliability.  Two deserve attention.  The inherent variability of wind and solar generation creates power transients and those fluctuations need to be addressed.  The problem is that the magnitude of this problem is new and it is likely that learning how to address it is difficult to anticipate so corrections will be reactions to problems.  Supporters of the Climate Act transition seem to think that existing wind, solar and energy storage resources only need to be scaled up to the quantity needed.  What they miss is that the more resources built the less those resources will be used.  Tverberg points out that low-capacity factors hurts energy return on investment payback.  All of these issues should be considered but have not been addressed in the Scoping Plan.

Tverberg also point that the word “sustainable” has created unrealistic expectations with respect to intermittent wind and solar electricity.  She illustrates this issue as follows:

A person in the wind turbine repair industry once told me, “Wind turbines run on a steady supply of replacement parts.” Individual parts may be made to last 20-years, or even longer, but there are so many parts that some are likely to need replacement long before that time. An article in Windpower Engineering says, “Turbine gearboxes are typically given a design life of 20 years, but few make it past the 10-year mark.”

She notes that “energy modeling has led to unrealistic expectations for wind and solar”.  This is evident in the Integration Analysis projections.  It should be obvious that the Scoping Plan projections for future generating resources have to be reconciled with the work of the New York Independent System Operator but, so far, no plan has been announced to do that.

Finally, Tverberg argues that current pricing plans that enable the growth of wind and solar electricity have consequences.  They are displacing existing dispatchable resources such that those resources are no longer viable.  The result is “pushing a number of areas in the world toward a “freezing-in-the-dark” problem”.  She concludes: “The world is a very long way from producing enough wind and solar to solve its energy problems, especially its need for heat in winter.”


I cannot improve on Planning Engineer’s conclusion.  Substitute New York for California and his conclusion sums up the issue that the Climate Action Council should address in the Scoping Plan:

Will California learn to avoid peak rolling blackouts?  If reliability were a primary concern, this situation shouldn’t bubble up again in a few years. California should be able to properly credit the ability of its power resources and match them to projected weather ensuring adequate power. If other priorities prevent responsible steps to ensure reliability, then those priorities, not the weather, should claim responsibility for the consequences. If California wants to continue as they have, they should be honest and make statements such as the following:

This is the end of affordable, reliable electric service as we understood it for most of the last 50 years. We are choosing to go with “green “technology to deal with the climate crisis. Keeping past reliability levels will raise your costs tremendously. As we try to put on limit on costs this will decrease your reliability. At times the power will not be there. We’ve all got help each other out.

Follow Up to RFF Inflation Reduction Act Retail Electric Rate Cost Analysis

This is a follow up to my article published at Watts Up With That Resources for the Future: Retail Electricity Rates Under the Inflation Reduction Act of 2022  and re-published here.  The article addressed the  Resources for the Future (RFF) Issues Brief titled Retail Electricity Rates Under the Inflation Reduction Act of 2022 claim that the legislation, will “save typical American households up to $220 per year over the next decade and substantially reduce electricity price volatility.”  I got a comment here that raised two flaws in my arguments.  I used data from the United States Energy Information Administration (EIA) Electricity Data Browser for Texas to test the hypothesis that increased renewable energy resources would lower electricity costs.  This article addresses the flaws raised.

The comment that exposed my flawed argument was provided by Dr. Michael Giberson, associate professor of practice in the Area of Energy, Economics, and Law with the Rawls College of Business at Texas Tech University.  He commented that:

When I follow your directions for your chart using the EIA data you describe, I get a very different picture. Avg residential power prices in Texas peak in mid 2008, then fall for several years before coming up more recently. Your chart is showing something other than what you describe.

Further, inflation adjusted power prices have been falling over the 2001-2022 period. Using CPI data with January 2022 = 100, average real price in early 2001 was about 12.5 cents then jumped up to 18.5 cents in mid 2008 before falling back to about 12.5 cents in 2022.

I hypothesized that if I used the United States Energy Information Administration (EIA) Electricity Data Browser  tool I could find data that showed that prices would go up in states where renewable energy development has increased the fraction of renewable energy generated and I used Texas an example.   I downloaded the monthly total net generation (GWh) and the net generation from just renewable resources so I could calculate the percentage of renewable generation energy.  Then I downloaded the average monthly residential average price of electricity. 

I went back and reviewed my work and have to apologize to everyone because I mistakenly used the wrong monthly residential cost data.  Dr. Giberson used the correct data as shown below.  The Texas data do not illustrate any relationship between the percentage of monthly renewable energy generated per month (left axis) and the monthly residential electric price (right axis).  What it does show is that the observed variability of the monthly prices is large in Texas. 

Importantly, this result invalidates my hypothesis that these two parameters could be used to show that when the Texas electric system added more renewable energy the costs went up.  Obviously, these data do not confirm that hypothesis.  Upon further review in order to pick out a trend in the cost data I should have adjusted for inflation as Dr. Giberson suggested.  The variation in the data before the renewable energy production kicked in also suggests that picking out a trend is more complicated than I thought it would be. 

An alternative hypothesis is that this is an issue with just the Texas data so I did the same thing with California data.  The results shown below are significantly different than Texas.  There is less cost variability and the increase after 2005 is not as pronounced.   It does appear that costs go up and renewable penetration goes up but I did not adjust for inflation to test that theory.

The axes in the Texas and California charts are different so inter-comparison is difficult.  When combined the results are messy but there are a couple of interesting things.  Texas residential electric costs are significantly lower (89% in 2021) and the spread has increased over time.  However, during the years 2005 to 2009 the Texas energy costs were less than 20% lower apparently because something happened to the Texas market in that time.  Dr. Giberson notes that the inflation adjusted real price in early 2001 was about 12.5 cents then jumped up to 18.5 cents in mid-2008 before falling back to about 12.5 cents in 2022. The other interesting point is that as the percentage of renewable generation increases the spread between the monthly values increases which I think reflects seasonal variations in resource availability.

I also extracted data for the United States as a whole. Note that US residential electric costs increased at the same time Texas rates increased after 2005.  The same volatility increase as additional renewable power is added is apparent.  It is notable that historically there has been a clear annual cycle of costs peaking in the summer and troughing out in the winter.  With regards to the RFF cost projection, I don’t think there is much evidence that increasing renewable penetration has increased cost but the annual cycle appears to be becoming less pronounced.  Of course, trying to analyze a trend when there was a pandemic is likely to end up with massive uncertainty.

As noted, there is one aspect that is consistent for all the renewable penetration data.  As the percentage of renewable energy production increases the volatility of the monthly production increases.  Wind resources are generally higher when there is a greater contrast in air masses in the spring and fall.  Obviously solar resources are lower in the winter when days are shorter.  I believe that there is an important outcome of that finding.  The RFF brief claims that adding more renewable resources will “substantially reduce electricity price volatility”.  I believe that the argument is that the price of fossil fuels is subject to many extraneous factors that affect price but those factors are smaller for renewable resources.  I think these data suggest that the inherent variability in a weather-dependent source of power generation could increase electric price volatility as the system becomes more dependent upon those resources. 

The following figure lists cost data for Texas. California, and the country as a whole.  What interests me are the outliers.  For example, in March 2014 the monthly residential price of electricity in California was 15.86 cents.  It dropped to 10.12 cents in April then rebounded to 16.46 cents in May.  Subsequent outliers are all either in October or April for the next five years.  This might represent increased wind availability but it is not clear why it is not as pronounced before or after this period if that is the case.

More important are the high outliers.  In California, the monthly price was 15.17 cents in June 2005, jumped to 16.65 cents in July, and then dropped to 14.89 cents in August.  In Texas, the monthly price was 11.4 cents in January 2021, jumped to 12.74 cents in February, and then went down to 11.5 cents in March.  The Texas blackout was the cause for the energy price spike in February 2021 but I don’t know of any specific problem in California in July 2005.  I suspect that these events will become more common as renewable penetration increases but the data do not show that yet.


Obviously, I need to double check my data analyses before publishing.  I found that using the correct data leads to an analysis that is consistent with every other aspect of the net-zero transition that I have looked at.  Everything is more complicated than it appears at first glance and any conclusions drawn are more uncertain.  Any claims about conclusive evidence should be regarded cynically.

The RFF Retail Electricity Rates Under the Inflation Reduction Act of 2022 issues brief claims that the legislation, will “save typical American households up to $220 per year over the next decade and substantially reduce electricity price volatility.”  My original conclusion was that the Texas cost and renewable generation data showed that it was unlikely that there would be cost savings due to increased renewable energy but I used incorrect data.  Using the correct data, I could argue that the Texas results did not show a decrease which is contrary to the RFF projection, but it is also reasonable to argue that were it not for the renewable generation that costs would have increased more than they did.  At first glance and without adjusting for inflation, California data suggested that increased penetration of renewable resources increases costs but there are clear uncertainties that make this a tenuous conclusion.

Despite the problems with my analysis, I remain convinced that the RFF projection is unlikely. The models used for this kind of analysis do not do future changes to the electric system well. For example in the comments on my original post, Rud Istvan explained why wind renewables cannot reduce electricity prices.  He showed that EIA LCOE estimates do not accurately project future costs for renewable energy development because they don’t include the costs to make the energy generated available when and where it is needed.  Francis Menton recently made a persuasive argument that all projections for future electric systems overbuild the wind and solar resources resulting in higher costs.  Worse, you still need a backup dispatchable resource and someone also has to provide ancillary services to maintain the grid’s ability to move power around.  I believe that the modeling down by RFF and others does not adequately take those factors into account and if it did it would not show reduced costs.

One final point about the data.  There is a real trend in the renewable energy generation data that needs to be watched in the future.  All the data show that as the percentage of renewable energy production increases the volatility of the monthly production increases.  The RFF brief claims that adding more renewable resources will “substantially reduce electricity price volatility”.   While there is no apparent impact in retail costs due to this observed volatility in these data, I suspect that will change in the future. 

Time Magazine Climate Anarchy

This article first appeared at Watts Up With That. I slightly modified the first paragraph but the rest is the same. This represents my opinion and not the opinion of any of my previous employers or any other company with which I have been associated. 

Based on the Time Magazine opinion piece, “What Comes After the Coming Climate Anarchy?”, we may have reached a point where no facts have to be included in a climate fear porn editorial.  This is just a short introduction to the piece and the author.  I encourage you to read it yourself.  After my post was published David Middleton wrote another article about the opinion piece covering much the same ground.  His version has much better graphics.

The author is Parag Khanna who Time describes as a founder of Future Map and author of the new book MOVE: The Forces Uprooting UsAccording to Khanna’s long bio, he is a “leading global strategy advisor, world traveler, and best-selling author”. He is Founder & CEO of Climate Alpha, an AI-powered analytics platform that forecasts asset values because “the next real estate boom will be in climate resilient regions”.   He also is Founder & Managing Partner of FutureMap, a data and scenario based strategic advisory firm that “navigates the dynamics of globalization”.  Dr. Khanna “holds a PhD in international relations from the London School of Economics, and Bachelors and Masters degrees from the School of Foreign Service at Georgetown University”.  A quick look at the School of Foreign Service Georgetown core curriculum offers no suggestion of any scientific requirements that could provide a basis for Dr. Khanna’s climate beliefs.

The opinion piece starts out with correlation causation fallacy endemic to the scientifically illiterate and climate innumerate crisis mongers.  He notes that in 2021, “global carbon dioxide emissions reached 36.3 billion tons, the highest volume ever recorded” and that this year “the number of international refugees will cross 30 million, also the highest figure ever”. Then he explains the basis for his climate anarchy belief: “As sea levels and temperatures rise and geopolitical tensions flare, it’s hard to avoid the conclusion that humanity is veering towards systemic breakdown”.

This is just a windup to:

Today it’s fashionable to speak of civilizational collapse. The U.N. Food and Agriculture Organization’s (FAO) states that just a 1.5 degree Celsius rise will prove devastating to the world’s food systems by 2025. Meanwhile, the most recent IPCC report warns that we must reverse emissions by 2025 or face an irreversible accelerating breakdown in critical ecosystems, and that even if the Paris agreement goals are implemented, a 2.4 degree Celsius rise is all but inevitable. In other words, the “worst case” RCP 8.5 scenario used in many climate models is actually a baseline. The large but banal numbers you read—$2 trillion in annual economic damage, 10-15% lower global GDP, etc.—are themselves likely massively understated. The climate bill just passed by the Senate is barely a consolation prize in this drama: a welcome measure, but also too little to bring rains back to drought-stricken regions in America or worldwide.

Then there is this:

Let’s assume that we are indeed hurtling towards the worst-case scenario by 2050: Hundreds of millions of people perish in heatwaves and forest fires, earthquakes and tsunamis, droughts and floods, state failures and protracted wars. Henry Gee, editor of the magazine Nature, wrote in an essay in Scientific American in late 2021 that even absent the hazards of climate change and nuclear war, humankind was heading towards extinction due to declining genetic variety and sperm quality.

He goes on to predict that even in the most plausibly dire scenarios billions of people will survive.  He says that current population stands at eight billion but claims as a result of these dire scenarios “the world population would likely still stand at 6 billion people by 2050”.  As you read on this opinion piece is simply an infomercial for Climate Alpha and FutureMap.  He believes that climate migrations will be necessary for the survivors.  His future vision is pockets of reliable agricultural output and relative climate resilience that may become havens for climate refugees.

He concludes:

What these surviving societies and communities will have in common is that they are able to unwind the complexity that has felled our predecessors. They rely less on far-flung global supply chains by locally growing their own food, generating energy from renewable resources, and utilizing additive manufacturing. A combination of prepping and nomadism, high-tech and simple, are the ingredients for species-level survival.

These demographic, geographic, and technological shifts are evidence that we are already doing things differently now rather than waiting for an inevitable “collapse” or mass extinction event. They also suggest the embrace of a new model of civilization that is both more mobile and more sustainable than our present sedentary and industrial one. The collapse of civilizations is a feature of history, but Civilization with a big ‘C’ carries on, absorbing useful technologies and values from the past before it is buried. Today’s innovations will be tomorrow’s platforms. Indeed, the faster we embrace these artifacts of our next Civilization, the more likely we are to avoid the collapse of our present one. Humanity will come together again—whether or not it falls apart first.


In my opinion there are several major flaws in his arguments.  Apparently, his projections are based on the RCP 8.5 scenario because he thinks it is “actually a baseline”.  Roger Pielke, Jr. has noted that the misuse of RCP8.5 is pervasive.  Larry Kummer writing at Climate Etc. explains that it is a useful worst-case scenario, but not “business as usual”.  For crying out loud even the BBC understands that the scenario is “exceedingly unlikely”.  Relying on that scenario invalidates his projections.

Khanna’s worst-case scenario statement “Hundreds of millions of people perish in heatwaves and forest fires, earthquakes and tsunamis, droughts and floods, state failures and protracted wars” is absurd.  He has to address the many examples that show that weather-related impacts have been going down as global temperatures have increased such as those described by Willis Eschenbach in “Where Is The “Climate Emergency?”.   The theme of his opinion is climate anarchy so why are earthquakes and tsunamis included?  I concede that his flawed climate projections could stress states and prolong wars but I am not convinced that climate is a major driver.

Finally, his argument that climate is a major driver is contradicted by his dependence on the Sustainable Development Index, a “ranking of countries that meet their people’s needs with low per capita resource consumption”.  He states that the best performers are “Costa Rica, Albania, Georgia, and other less populated countries around middle-income status”.  The fact that Costa Rica is in a tropical region and thus much warmer than mid-latitude Albania and Georgia suggests that warm climates are not a limiting factor for sustainable development.

Khanna may be a leading global strategy advisor, world traveler, and best-selling author but his lack of understanding of the uncertainties associated with climate change are evident in this editorial.  Not unlike many of those advocates for climate change action, upon close review it appears that following the money is his motivation.

Resources for the Future: Retail Electricity Rates Under the Inflation Reduction Act of 2022

This post first appeared at Watts Up With That

Resources for the Future (RFF) has published an Issues Brief titled Retail Electricity Rates Under the Inflation Reduction Act of 2022.  According to the report the Inflation Reduction Act (IRA) legislation, will “save typical American households up to $220 per year over the next decade and substantially reduce electricity price volatility.”  This setoff my BS detector so I got some data from Texas to see if the state with the most total renewable energy production has seen reduced costs from their wind and solar development.

The Climate Act establishes a “Net Zero” target (85% reduction and 15% offset of emissions) by 2050.  I have written extensively on implementation of the Climate Act.  Everyone wants to do right by the environment to the extent that efforts will make a positive impact at an affordable level.  Based on my analysis of the Climate Act I don’t think that will be the case.  I believe that the ambitions for a zero-emissions economy outstrip available renewable technology such that the transition to an electric system relying on wind and solar will do more harm than good.  The opinions expressed in this post do not reflect the position of any of my previous employers or any other company I have been associated with, these comments are mine alone.

I am not going to address the IRA provisions directly.  The Institute for Energy Research described the huge renewable tax incentives and subsidies earlier this week.  Anthony Watts applauded the Wall Street Journal and Bjorn Lomborg for showing how useless the IRA is at tackling climate.  H. Sterling Burnett explained that the claims made about its effects on greenhouse gas emissions are “pure fantasy”. The RFF report was one of the analyses that alleged that the IRA would benefit consumers and I will focus solely on that.  This analysis is of particular interest to New Yorkers because this type of study was used in the Integration Analysis and I expect the drawbacks described below are present in that work as well.

RFF analyzed the effects on the crucial electricity sector using their in-house Haiku Electricity Market Model to “project electricity retail rates for a range of potential scenarios that account for variability in future fuel prices, capital and technology costs, and uptake of specific provisions of the legislation.  The analysis found that if the legislation is passed:

  • Retail costs of electricity are expected to decline 5.2-6.7 percent over the next decade, saving electricity consumers $209-278 billion, given expected natural gas prices.
  • The average household will experience approximately $170-$220 in annual savings from smaller electricity bills and reductions in the costs of goods and services over the next decade.
  • Ratepayers are insulated from volatility in natural gas prices, with electricity rates projected to decrease even under a high natural gas price scenario.
  • 2030 electricity sector emissions are projected to drop to 69.8 percent to 74.9 percent below 2005 levels, compared to 48.5 percent below 2005 levels without the policy.

The RFF Haiku model analyzes regional electricity markets and interregional electricity trade in the continental United States.  It is all the rage for consulting companies to develop an in-house model suitable for projecting future electric system resources.  RFF claims that:

“The model accounts for capacity planning, investment, and retirement over a multi-year horizon in a perfect foresight framework, and for system operation over seasons of the year and times of day. Market structure is represented by cost-of-service (average cost) pricing and market-based (marginal cost) pricing in various regions. The model includes detailed representation of state-level policies including state and regional environmental markets for renewable energy and carbon emissions and frequently has been used to advise state and regional planning.”

I have had to deal with these electric production and costs models for over 40 years. I cannot over emphasize that even the most sophisticated of these models have difficulties dealing with the generation capacity needed for peak loads and the intricacies of the transmission grid.  The Haiku Electricity Market Model documentation shows that the model is so simplified that I don’t think it can get reasonable projections correct.    For example, the model simulates the contiguous United States with 21 regions and calculates the transmission between those regions in order to estimate capacity requirements.  New York alone has eleven control areas and the transmission constraints for those areas and adjoining regions are needed to accurately estimate generating resource needs.  All the little constraints that are averaged out in the RFF model mask a major portion of the capacity requirements and energy needs that under-estimate costs.  This is a particular problem as more and more wind and solar energy resources are added to systems.  The RFF model and others like it have consistently under-estimated the emission reductions from fuel switching from coal and oil to natural gas electricity production and I think they are under estimating the difficulty replacing natural gas generation with wind and solar.  Moreover, somebody, somewhere has to account for the intermittent nature and lack of ancillary services from wind and solar.  I don’t think a simple model can capture those costs.

On the other hand, if adding renewable resources in certain jurisdictions has led to lower costs then my reservations are wrong.  According to a recent US News and World Report article Texas produces produce the most total renewable energy (millions of megawatt-hours), according to the U.S. Energy Information Administration.  That article notes that: “In the first quarter of 2022, Texas led all states in overall renewable energy production, accounting for over 14% of the country’s totals, due in large part to the state’s prolific wind energy program”.

The United States Energy Information Administration (EIA) Electricity Data Browser  enables a user to access electricity generation and consumption data as well as electricity sales information.  The data can be filtered as needed.  I filtered the data to look only at Texas data.  I downloaded the monthly total net generation (GWh) and the net generation from just renewable resources so I could calculate the percentage of renewable generation energy.  Then I downloaded the average monthly residential average price of electricity.  The following graph shows the results.  The residential cost of electricity has been increasing steadily since 2001.  The percentage of renewable energy has increased from almost nothing in 2001 to recent months over 30%.  I am not seeing that the deployment of renewable resources produced a reduction in costs.

In conclusion, the Texas data do not show that renewable energy deployment reduces costs.  The RFF projections that the IRA will reduce costs due to renewable development are very unlikely because the overly simplified model cannot reproduce the features of the electric system that lead to higher prices from intermittent wind and solar resources. 

If anyone, anywhere can find any jurisdiction where the development of massive amounts of wind and solar reduced prices please let me know.  In the meantime, I call your attention to the comments of Rud Istvan at the Watts Up with That article who explains that:

Renewables (wind) CANNOT reduce electricity rates, period.

The EIA LCOE has since at least 2015 claimed on shore wind was at parity with CCGT. This is simply false, based on deliberately bad underlying assumptions. The worst is that EIA explicitly assumes both have useful capital lives of 30 years. That is at best gross negligence, at worst deliberate prevarication. The modern on shore big wind turbines (~2-3 MW each) have at best 20 year lives. The problem is inherent in the uneven axial bearing loading since wind at the top has a higher velocity than wind at the bottom. Axial bearing failure is sudden death, and for an older turbine not worth a very expensive repair. CCGT has at worst a 40 year life (GE warranty). And in practice 45-50.

Some years ago (2016 IIRC) over at Judith’s I posted ‘True cost of wind’ illustrating then fixing the basic obvious EIA errors. The result was CCGT LCOE about $58/MWh, while wind (based on the Texas ERCOT grid at then about 10% penetration) was $146/MWh.

No amount of IRA incentivizing or Biden pontificating can fix the basic problem that wind is MUCH more expensive. And this is also easily demonstrated for Europe without EIA LCOE annuity calculations by simply graphing wind penetration versus retail electrify rates by country. A very strong positive linear correlation. Higher penetration always means higher rates.

Resource Adequacy Modeling for a High Renewable Future

In the process of preparing an article about the New York State Reliability Council (NYSRC) Executive Committee approval of the Extreme Conditions Whitepaper on July 8, 2022, I found a reference to a very nice report Resource Adequacy Modeling for a High Renewable Future.  The report provides important background information necessary to understand the NYSRC whitepaper so my first thought was to include a summary of the report in the NYSRC post.  It made the article too long so this post focuses exclusively on the background paper.

Everyone wants to do right by the environment to the extent that efforts will make a positive impact at an affordable level.  I have written extensively on implementation of New York’s Climate Leadership and Community Protection Act (Climate Act) because I believe the ambitions for a zero-emissions economy embodied in the Climate Act outstrip available renewable technology such that it will do more harm than good.  This post also addresses the mis-conception of many on the Climate Action Council that an electric system with zero-emissions is without risk.  The opinions expressed in this post are based on my extensive meteorological education and background and do not reflect the position of any of my previous employers or any other company I have been associated with, these comments are mine alone.

Resource Adequacy Modeling for a High Renewable Future

The National Regulatory Research Institute (NRRI) is the research arm of the National

Association of Regulatory Utility Commissioners (NARUC).  NRRI provides research, training, and technical support to State Public Utility Commissions. The June 2022 report “Resource Adequacy Modeling for a High Renewable Future “gives an excellent overview of electric resource adequacy planning as performed today and describes what they think will be needed in the future.

Traditional Resource Adequacy Planning

The report describes traditional resource adequacy planning:

Electric utilities have used the resource planning process for decades to develop long-term, least-cost generation supply plans to serve expected customer demand. Resource adequacy planning ensures that a system has enough energy generation throughout the year to serve demand with an acceptably low chance of shortfalls.  Resource adequacy is measured by the metrics described in Figure 1.  Reliability metrics provide an indication of the probability of a shortfall of generation to meet load (LOLP), the frequency of shortfalls (LOLE and LOLH), and the severity of the shortfalls (EUE and MW Short).

The industry has traditionally framed resource adequacy in terms of procuring enough resources (primarily generation) to meet the seasonal peak load forecast, plus some contingency reserves to address generation and transmission failures and/or derates in the system.  This approach and the metric used to define it is called the “reserve margin.”  Planners establish a reserve margin target based on load forecast uncertainty and the probability of generation outages. Required reserve margins vary by system and jurisdiction, but planners frequently target a reserve margin of 15 percent to 18 percent to maintain resource adequacy. Figure 2 shows the standard conceptualization of a load duration curve, rank ordering the level of a power system’s load for each hour of the year from highest to lowest on an average or median basis in a typical weather year. The installed reserve margin is a margin of safety to cover higher than expected load and/or unexpected losses in generation capacity due to outages.

Pechman, C. Whither the FERC, National Regulatory Research Institute. January 2021, available at pub/46E267C1-155D-0A36-3108-22A019AB30F6.

New York resource planning analyses use the “one day in ten years,” criteria (LOLE), meaning that load does not exceed supply more than 24 hours in a 10-year period, or its equivalent metric of 2.4 hours loss of load hours (LOLH) per year. This analysis is performed at the “bal­ancing authority” (BA) level. In the past New York BAs were vertically integrated utilities with defined service terri­tories. After deregulation this responsibility passed to the state’s independent system operator (ISO).  The region covered now includes many utility service territories.  More importantly the New York Independent System Operator (NYISO) has to develop market or compliance-based rules to main­tain sufficient system capacity which adds another layer of complexity.  BA’s typically conduct resource adequacy analysis based on their own load and resources. The NYISO does their resource adequacy planning using resources within its geographic region or have firm transmission deliverability into the New York Control Area (NYCA).  There is another complication in the state.  New York City has limited transmission connectivity so there are specific reliability requirements for the amount of in-city generation that has to be operating and other rules to prevent blackouts.

The report goes on to note:

The standard metrics shown in Figure 1are generally reported as mean values of simulated power system outcomes over a range of potential future states, but planners also need to understand and plan for the worst-case outcomes and associated probability of such outcomes. Figure 3shows the mean and percen­tile values for loss of load hours for a power system over a three-year period.

In Figure 3,on average, the power system is resource adequate, remaining below the target of 2.4 hours per year. However, if the power system planner were more risk averse, she might want to bring a higher percentile line under the 2.4-hour target. She would need to add more firm capacity, adding to customer cost. The 95th percentile is the worst-case outcome, providing addi­tional information on the upper bound risk of outages for a given portfolio. Only power systems with no recourse to import energy in a shortage, such as an island, would consider planning to the 95th percentile due to its high cost.

The report’s traditional planning section concludes with this:

Resource adequacy planning is fundamentally con­cerned with low probability events and planning for average outcomes; although a common practice, this planning is not sufficient and increasingly risky with more uncertain supply, such as renewables. In the past, planners only needed to worry about unusually high loads or high forced outages. Now, they must worry about unusually high loads during periods of unusually low renewable output and limited storage duration. Adding supply uncertainty and, as we discuss later, more extreme weather, compounds risks and thus requires a fundamental rethinking of planning for low probability, high impact tail events.

Problems with Traditional Resource Planning with a High-Renewable System

Despite the fact that the NYISO and the consultants for the Integration Analysis that provides the framework for the Climate Act Draft Scoping Plan have identified a serious resource adequacy problem, there are vocal members of the Climate Action Council who claim there are no reliability concerns for the future 100% zero-emissions New York electric grid.  However, analyses have shown otherwise.  E3 in their presentation to the Power Generation Advisory Panel on September 16, 2020 noted that firm capacity is needed to meet multi-day periods of low wind and solar output.  The NYISO Climate Change Phase II Study also noted that those wind lull period would be problematic in the future.

The NRRI report opens the discussion of the new problems that have to be addressed:

With weather emerging as a fundamental driver of power system conditions, planning for resource ade­quacy with high renewables and storage becomes an exercise in quantifying and managing increasing uncer­tainty on both the supply and demand side of the equation. On the load side, building electrification, electric vehicle adoption, and expected growth in customer-sited solar and storage are likely to have pronounced effects on future electric consumption. Uncertain load growth and changing daily consump­tion patterns increase the challenge of making sure that future resources can serve load around the clock. Simply modeling future load based on past load with added noise does not characterize uncertainty from demand side changes.

The report goes on to explain that supply-side changes create a need for new modeling approaches.  In particular, the traditional system consists mostly of dispatchable resources that operators can control as necessary to keep the generation matched with the load.  In the future the system will be comprised mostly of resources with limited or no dispatchability. Table 1 compares past approaches with current needs.  Note that weather impacts need to be “Incorporated as a structural variable driving system demand, renewable generation, and available thermal capacity”. 

There is another fundamental change.  In the past the resource adequacy modeling could use average annual generation profiles to meet expected loads.  In the future, there will have to be: “multiple renewable generation simulations using historical generation and weather data”. The modeling scenarios will need to meet future expected resource development and maintain the correlation

between renewable availability and load.  In particular, the highest and lowest temperatures and thus the expected high loads are typically associated with large high-pressure systems that have low wind speeds and thus low wind resource availability.

The NRRI report shows an approach that addresses these concerns in Figure 5.  The report notes:

Weather, primarily in the form of temperature, but potentially including insola­tion, humidity, wind speed, etc., drives simulations of renewable generation and customer load. Generation outage simulations can be modeled as random (the traditional approach) or as correlated with extreme heat or cold events. Once the simulations are in place, models can compute multiple future paths on an hour-by-hour basis to determine when load cannot be fully served with the available resources. For every hour of the model time horizon, there are independent simulations of load, renewables, and forced outages to determine if load shedding must occur. If a particular model contains 100 simulations and four show a lack of resources to serve load for a particular hour, the hour in question would have a loss of load probability of 0.04 (4/100).

In my opinion, the weather drivers have to be carefully considered.  In my Comment on Renewable Energy Resource Availability  on the Draft Scoping Plan, I explained why an accurate and detailed evaluation of renewable energy resource availability is crucial to determine the generation and energy storage requirements of the future New York electrical system.  I showed that there is a viable approach using over 70 years of data that could robustly quantify the worst-case renewable energy resources and provide the information necessary for adequate planning. 

The problem however is what will be the worst case?  The NRRI report brings up the issue of energy storage:

Energy storage presents a unique challenge in re­source adequacy models. Unlike traditional resources, storage devices such as batteries, compressed air, or pumped-hydro act as both load and generation de­pending on whether they are charging or discharging. Modern resource adequacy models need to simulate this behavior when determining the capability of en­ergy storage to serve load during periods of resource scarcity. What state of charge should we expect for energy storage at times when the storage is truly needed? Are batteries likely to be fully charged at 6:00 PM on a weekday in August? What about grid charging versus closed systems where batteries must charge from a renewable resource? At the high end of renew­able penetration, how much storage would be required to cover Dunkelflaute, the “dark doldrums,” that occur in the winter when wind ceases to blow for several days. Questions surrounding the effective load-carrying capability of energy storage significantly increase the complexity in modeling resource adequacy.

The worst-case meteorology has to consider the energy storage resource.  The worst-case may not be the lowest amount of wind and solar resources over a few days.  Instead, it could be an extended period of conditions that prevent battery re-charging.  I suspect that the long-term historical records will be used to identify potential problems and then a set of scenarios based on different meteorological regimes will be developed that can be used to address the questions raised in the previous paragraph.

The NRRI report explains how this might work:

Figure 6 provides an illustration of modeling the use of batteries in resource adequacy. The figure shows bat­tery storage in blue, load in orange, and the available thermal generation in grey. When load exceeds thermal generation, the system is forced to rely on battery discharge for capacity. If the event lasts long enough to fully discharge the battery, the green line (generation minus load) will turn negative, indicating a load shed event.

The report goes on to explain how the modeling analysis is done.  It notes that:

Simulations of random variables fit Monte Carlo meth­ods by creating multiple future time series of the ran­dom variables, while maintaining correlation across time within variables (if wind is high in hour 1, it will likely be high in hour 2) and correlations between the variables, such as the strong relationship between temperature and load. If wind tends to be higher in the spring and fall, the simulations will exhibit that trend. Monte Carlo applications differ dramatically between resource adequacy models, with some models using a sequential approach that solves the model in hourly steps whereas others use techniques that solve the models quickly without stepping through each hour. Accurate representation of energy storage in resource adequacy models necessitates sequential solution techniques to account for the time dependencies for storage state of charge inherent in models.

I believe it is necessary to use the worst-case meteorological scenarios as the primary driver of these simulations.  In other words, the Monte Carlo weather parameter adjustments should be small increments on top of the observed values.  The report is talking primarily about correlations in time but spatial correlations are a critical wind resource availability consideration too. 

The NRRI report addresses my concerns.

When using the Monte Carlo approach with weather as a fundamental driver, individual simulations represent independent futures for weather, load, and renewables. Realistic simulations maintain the statistical properties of the underly­ing resource and correlation be­tween resources and load. For example, if historic data show no correlation between load and wind generation, the simulations should maintain this relationship unless a reasonable expectation exists for correlations to change in the future

However, they use simple examples of the load and resource correlations.  There are those that believe that because the wind is always blowing somewhere that transmission upgrades will ensure reliability.  However, if during the worst-case conditions New York has to rely on wind resources in Iowa because the high-pressure system is huge, that may not be practical.  I cannot over-emphasize the need for an analysis that simulates wind and solar resource availability over wide areas.  As the report notes analyses that fail to replicate the proper correlation between wind, solar, and load for the electric grid can underestimate the risk of load shedding.

The report goes on to explain other adjustments to traditional resource planning that will be necessary to address a high renewable future.  That discussion is beyond the scope of my concern.  The report concludes:

The electric grid is transitioning quickly from a system of large, dispatchable generators to a system reliant on high levels of variable renewable energy, energy storage, and bi-directional flow. Against this backdrop, analytical tools used for decision making regarding resource adequacy are more important than ever and those tools need to evolve to meet the modern grid challenges outlined in this paper. Models based in realistic weather-driven simulations more accurately capture the risk of load shedding due to inadequate generation. Simulations derived from historical data ensure models include load and generation patterns as well as correlations among resources and the ability to adjust to future climate conditions. Models that do not account for these factors may lead to decisions that underinvest in resources or invest in the wrong re­sources. Recent events in California and Texas indicate the importance of getting these projections right to keep the grid reliable.

To model resource adequacy in future power systems with high penetration of renewables, we recommend several enhancements in modeling tools and tech­niques. Modeling tools should simulate key structural variables and allow for validation of the simulations by benchmarking against the historical data used to create the simulations. While maintaining statistical properties derived from historical data, simulations should also include future expectations of load growth along with changes in seasonal and daily load shapes. Genera­tion-forced outage simulations should include the possibility of correlated outages from extreme weather. Finally, climate change will drive more weather events in the power system and this risk should be accounted for in the models, at least in the form of sensitivity cases or stress tests.


I found this report to be a very useful description of the particulars of electric grid reliability analysis now and in the future.  It is clear that the transition to a high renewable future introduces issues that could cause problems.

Finally, this report and other similar studies always claim that climate change should be considered in future analyses.  As I will explain in my future article on the NYSRC Extreme Conditions Whitepaper I believe that the most important future weather concern is that changing the resource mix to one relying upon weather-dependent wind and solar generation is the critical vulnerability that has to be addressed.  I think that the trend of extreme weather events due to greenhouse gas concentrations in the atmosphere is much smaller than natural variability.  Therefore, using a long record of data for evaluation will cover most of the potential future variability.  Unfortunately, recent major blackouts due to extreme weather suggest that we haven’t even been able to plan for the past.  So far New York has avoided such a blackout either due to more stringent standards and better policy development or luck.