HIGH DEMAND AND LOW WIND AND SOLAR DURING SUMMER IN NEW ENGLAND

This article assumes the highly productive (CF = 0.90), near-CO2-free, NE nuclear plants would be closed in 2035, when their licenses would have expired, but the highly efficient (up to 60%), low-CO2, gas turbine plants would continue to operate as at present. 

 

Wind and solar (after the meter, ATM + before the meter, BTM) would be greatly increased by 2035, based on ISO-NE projections; 32% of a total NE grid load, versus 5.5% in 2018.

 

As a result of replacing low cost-nuclear with high-cost wind and solar and a lot of grid addition and grid-scale battery systems, household electric rates would become significantly higher, as happened in California, and in Germany, Denmark, and other high RE nations in Europe. See URLs.

http://www.windtaskforce.org/profiles/blogs/the-more-wind-and-solar...

 

High Electricity Demand Periods: High electricity demand on the New England grid occurs at least 100 hours of the year. Those high demand hours occur mostly during June, July and August.

 

During high demands, almost all the traditional generators (gas, oil, coal, nuclear, hydro, wood, municipal waste, etc.) connected to the NE grid would be operating near maximum output, and electricity imports, via tie lines, likely would be maximal. Wind and solar would provide whatever, depending on sun and wind conditions.

 

If demand conditions warrant, as judged by ISO-NE, the grid operator,

 

1) Some reserve oil and coal plants would be started and be synchronous mode, so they would be ready to feed their output into the grid, as ordered by the grid operator. The owners of such plants would get paid for being “in reserve”, a common practice throughout the US and elsewhere in the world, because their plants would have to be kept in good order, staffed and fueled, ready to operate on a moment’s notice.

 

2) The grid operator would take offline pre-selected electric services to large users, who have agreed to such measures. Such users get paid for participating in the ISO-NE grid demand management program.

 

High-Reliability Electric Service Trumps All: Whereas many 100% RE proponents, who likely have never analyzed or designed any energy systems, and have been led to believe the California-originated mantra “wind, water, solar, WWS, can do it all”, are advocating no fossil and no nuclear plants, the Federal Energy Regulatory Commission, FERC, the Nuclear Regulatory Commission, NRC, and the Independent System Operator of New England, ISO-NE, would never allow such a scenario to unfold, because they are mandated, by law, to ensure electricity service, 24/7/365, at high reliability, at least 99.98%. It is a pre-eminent requirement above all others, not just in the US, but also in Europe, Japan, etc.

 

Excessive Wind and Solar on the NE Grid

 

This URL shows significant curtailments of wind and solar would be required, because too much wind and solar on the NE grid would overwhelm the up and down ramping capacity of the NE gas turbine plants.

https://arxiv.org/pdf/1812.04787.pdf

 

This is nothing new, as grids in Germany, Denmark, Ireland, the UK, etc., which have much higher levels of wind and solar than the NE grid, have had similar issues for at least 5 to 10 years. They deal with these issues using:

 

1) Increased tie lines to nearby grids that have hydro storage, such as Sweden and Norway, which, along with Denmark and Finland, are on the Nord Pool grid

2) Increased tie lines to other grids with excess up and down ramping capacity, such as the Netherlands and France

3) Curtailment during high wind and/or solar

4) Demand management 

5) Various forms of domestic storage

 

States With and Without Mandated Renewable Portfolio Standards

 

Here is an item of interest to many people regarding mandated RPS requirements, which require utilities to sell a certain percentage of their total electricity sales as renewables, such as wind, solar, wood burning, municipal waste burning, etc. Some states also count hydro as renewable.

 

States with mandated RPS requirements had electricity prices 26% higher than those without.

https://wattsupwiththat.com/2019/05/02/researchers-say-renewable-en...;

 

The 29 states with mandated RPS requirements (plus the District of Columbia) had average retail electricity prices of 11.93 c/kWh, according to the U.S. Energy Information Administration. 

 

The 21 states without mandated RPS requirements had average retail electricity prices of only 9.38 cents/kWh.

https://www.eia.gov/electricity/state/

 

The logical conclusion is, the more RE, the higher the electric rates, regardless of energy mix on the grid.

 

California, US and Vermont Electricity Prices, All Sectors: The weighted average US prices includes high California prices and quantities, a major component of the weighted average. Table 1 shows the weighted average US price including California. See URLs

 

http://www.neo.ne.gov/statshtml/204/204_2017.htm

https://www.eia.gov/electricity/state/California/

 

If California were removed, it would lower the US average. A comparison of California versus that lower US average shows California rates, all sectors, increased 24.06% and US rates (wo/California) only 5.45% during the 2010 - 2017 period.

 

California’s RE efforts are demonstrating, the more highly subsidized RE, the higher the electric rates. But that is only a part of the cost picture, as shown in section 1.

 

NOTE: The Vermont rates, all sectors, as posted by EIA, do not include the Efficiency Vermont surcharge and the Electric Assistance Program fee tacked onto electric bills, which has been increasing from about 6% in 2010 to about 8.0% in 2017 for most households. If EV and EAP charges were added, Vermont rates increased 12.12% and US rates (w/tiny Vermont) only 7.22% during the 2010 - 2017 period.

http://www.windtaskforce.org/profiles/blogs/efficiency-vermont

 

Year/All Sectors	CA	US, w/CA	US wo/CA	VT wo/EV & EAP	VT w/EV & EAP
	c/kWh	c/kWh	c/kWh	c/kWh	c/kWh
2010	13.01	9.83	9.58	13.24	14.03
2011	13.05	9.90	9.66	13.80	14.67
2012	13.53	9.84	9.55	14.42	15.36
2013	14.29	10.07	9.74	14.62	15.63
2014	15.23	10.45	10.08	14.58	15.63
2015	15.50	10.42	10.03	14.36	15.41
2016	15.23	10.27	9.89	14.46	15.57
2017	16.14	10.54	10.11	14.57	15.74
Increase, %	24.06	7.22	5.45	10.05	12.12

Germany and Denmark Household Electricity Prices: The above correlates well with this graphic, based on Eurostat data. Denmark and Germany have advanced the most along the wind and solar installation path. They have the highest household electric rates in Europe. See graphic and Appendix.

 

ISO-NE Real-Time Grid Operating Data 

 

Fortunately, ISO-NE posts real-time data regarding grid operations, every few minutes, on a daily basis.

 

See URL, go to fuel mix graph, click on rectangle with arrow and download the outputs, MW, of the various electricity sources connected to the NE high voltage grid. The corresponding real-time demand, MW, is also posted and can be downloaded.

https://www.iso-ne.com/isoexpress/web/charts

 

ISO-NE Monitoring of NE Grid

 

ISO-NE computers continuously monitor, calculate and and record the operations of each of the generating plants connected to the grid and of the ones feeding into the grid, such as:

 

Electricity generation, MWh

Maximum output capability, MW

Minimum output capability, MW

Output percentage, which enables calculating plant efficiency and fuel consumption

Fuel type, which enables calculating combustion CO2 emissions

Available up ramping, MW, and up ramping rate, MW/min

Available down ramping, MW, and down ramping rate, MW/min

 

ISO-NE sums the outputs of all the gas plants and posts the total each minute on its website, as do many other grid operators. It does the same with all the nuclear, solar, and wind plants, etc.

 

ISO-NE sums the available up ramping, and up ramping rate, and sums the available down ramping and down ramping rate. That information is not posted.

 

If a large generator, with maximum output capability of 1000 MW, has an unscheduled outage, almost all the other plants have to increase their outputs (perform up ramping) to fill the gap (some plants are exempt, such as nuclear plants).

 

If available up ramping is insufficient, ISO-NE can order two pumped storage plants to quickly feed their outputs into the grid by discharging water from their upper reservoirs through hydro turbine generators, located up to 1000 ft feet below their upper reservoirs.

 

If available up ramping is still insufficient, ISO-NE, under its demand management program, can shut off non-essential electric service to a number of users (they had voluntarily agreed to it, and do get paid for it). This quickly reduces demand.

 

Wind and Solar During Summer Lulls

 

Normally wind is minimal and solar is maximal during summer, but often times both are near zero, sometimes for 5 to 7 days in a row, such as during a 6-day period in June 2017, which was analyzed in this article. See URL

http://www.windtaskforce.org/profiles/blogs/analysis-of-a-6-day-lul...

 

NOTE: There was practically no wind and solar electricity during late April - early May of 2019, according to the ISO-NE published real-time, minute-by minute data. Such lulls occur at random, and have occurred in the past and can occur in the future, at anytime of the year.

Wind and Solar in Year 2035

 

It would be likely the following conditions would exist on the NE grid:

 

- All the nuclear plants would be shut down, because their licenses would have expired.

- All the gas, oil and coal plants would still be connected to the grid.

- The gas plants would operate as required, but the oil and coal plants would be “in reserve”.

- Electricity via tie lines, about 98% hydro from Canada, would increase as in table 4

- Installed wind and solar plants would increase as in table 1

- Electricity of wind and solar would increase as in table 4

- Electricity of various other sources would increase as in table 4

 

In table 1:

The 2030 values are estimates by ISO-NE, the grid operator

The 2035 values were extrapolated, based on installation rates during prior years.

ATM solar is after-the-meter solar fed to high voltage grids and monitored by ISO-NE, such as field-mounted.

BTM solar is before-the-meter solar fed to distribution grids, such as residential rooftop. It is estimated by local utilities and reported to ISO-NE.

CF is capacity factor.

A TWh is a billion kWh

 

Table 1/ Future wind and solar	MW in 2017	MW in 2030	MW in 2035
Wind, onshore and offshore	1279	7283	8500
Solar, before the meter, such as residential rooftop	1501	6000	7500
Solar, after the meter, such as field-mounted	890	6000	7500

 

Installed Solar, MW, and Production, TWh, Would Increase as in Table 2

 

Table 2/Solar	2017	2018	2018	2018	2035	2035	2035
Installed	MW	MW			MW
Production			TWh	CF		TWh	CF
BTM	1501	1799	2.162	0.137	7500	9.013	0.137
ATM	890	1067	1.212	0.130	7500	8.519	0.130
Total solar	2391	2866	3.374	0.134	15000	17.659	0.134

 

Installed Wind, MW, and Production, TWh, Would be as in Table 3

 

Table 3/Wind	2017	2018	2018	2018	2035	2035	2035
Installed	MW	MW			MW
Production			TWh	CF		TWh	CF
Onshore	1300	1300	3.232	0.284	4250	10.566	0.284
Offshore	35	35	0.135	0.440	4250	16.393	0.440
Total wind	1335	1335	3.367	0.288	8500	26.959	0.362

 

The Load on the NE Grid Would be as in Table 4

 

- 2018 are actual values.

- 2035 values for wind and solar were extrapolated from ISO-NE estimates for 2030

- The TWh/d are annual average values.

- Oil and coal plants could increase their production, but they have been placed in “reserve”

- It would be likely almost all of the energy efficiency of 10,000 TWh in 2035 would result in a reduction of gas generation from 50.511 TWh to about 40.511 TWh. However, increased use of heat pumps and EVs likely would add about 10,000 TWh/y of gas generation.

http://www.windtaskforce.org/profiles/blogs/replacing-gasoline-cons...

- New England would make NO difference no matter what it does, with India, China, etc., building hundreds of coal plants in future years. See table 4A.

 

Table 4A/Grid disturbing electricity	2018	2035
	TWh	TWh
Wind	3.367	26.959
ATM Solar	1.212	8.519
BTM Solar	2.162	9.013
Total wind and solar	6.741	44.491
World total electricity	26000.000

 

Table 4/NE electricity sources	2018	2018	2018	2035	2035	2035
	TWh	TWh/d	%	TWh	TWh/d	%
Fossil	52.781	0.145	42.680	52.781	0.145	33.01
Gas	50.511	0.138	40.844	50.511	0.138	31.59
Oil	1.161	0.003	0.939	1.161	0.003	0.73
Coal	1.109	0.003	0.897	1.109	0.003	0.69
Nuclear	31.385	0.086	25.379	0.000	0.000	0.00
Renewables	10.788	0.030	8.723	63.844	0.175	39.93
- Wind	3.367	0.009	2.723	26.959	0.074	19.36
- Refuse	3.018	0.008	2.440	4.000	0.011	2.50
- Wood	2.698	0.007	2.182	3.000	0.008	1.88
- ATM Solar	1.212	0.003	0.980	8.519	0.023	5.33
- Landfill methane	0.448	0.001	0.362	0.650	0.002	0.41
- Farm, etc., methane	0.045	0.000	0.036	0.100	0.000	0.06
Other	0.400	0.001	0.323	0.500	0.001	0.31
NE Hydro	8.708	0.024	7.041	10.000	0.027	6.25
Imported H-Q hydro via tielines	21.409	0.059	17.312	34.750	0.095	21.74
Pumping loss	-1.804	-0.005	-1.459	-2.000	-0.005	-1.25
Electricity fed to high voltage grid	123.667	0.339	100.000	139.259	0.382	100.00
BTM solar fed to distribution grids	2.162	0.006		9.013	0.025
Additional energy efficiency				10.000	0.027
Total net load on NE grid	121.505			120.246	0.329

 

Owners heating/cooling their houses and other buildings and charging their EVs to travel from A to B could not possibly rely on variable/intermittent wind and solar in New England. They need steady, 24/7/365 electricity at high reliability, as provided by gas turbine plants. See graphic.

 

Multi-Day Wind Solar Lull, With High Demand, During Summer of 2035  

 

Wind and Solar Deficit: If wind and solar were assumed to be 15% of annual averages during a multi-day summer lull, about 0.15 x (26.959, wind + 8.519, ATM solar + 9.013, BTM solar) = 6.674 TWh/y would be present, or 0.018 TWh/d, instead of an annual average of 44.491 TWh,/y, or 0.122 TWh/d, for a deficit of 0.122 - 0.018 = 0.104 TWh/d.

 

Offsetting the WS Deficit: In 2018, the NE grid had about 14,800 MW of gas plants, producing 50.511 TWh/y, or 0.138 TWh/d, at an average CF = 50.511 TWh/y/(8766 h/y x 14,800 MW) = 0.534.

https://www.iso-ne.com/about/key-stats/resource-mix

 

The average daily “power burn” of gas was 50.511 TWh/y x 1/0.50, efficiency x 3412 Btu/kWh x 1 cu ft/1000 Btu x 1 y/365 d = 0.944 Bcf/d 

 

These plants likely could produce at a CF = 0.80 during high demands in summer, and increase output from 0.138 TWh/d to 0.900/0.534 x 0.138 = 0.208 TWh/d, for an addition of 0.069 TWh/d.

 

The “power burn” of gas would be 0.800/0.534 x 0.944 = 1.416 bcf/d,for an addition of 0.472 bcf/d.   

 

There are two alternatives:

 

1) The “Reserve” oil and coal plants could be put on line to add another 0.035 TWh/d, for a total addition of 0.069 + 0.035 = 0.104 TWh/d, which would offset the deficit. See table 6.

 

2) The demand management program could be activated to reduce demand by 0.035 TWh/d, which would reduce the remaining deficit to zero. 

 

If the two alternatives were insufficient, batteries, and/or additional hydro imports via tie lines, and/or additional “reserve” gas turbine capacity with additional gas storage facilities would be required, which would especially be the case, if even more wind and solar would be added after 2035.

 

NOTE: The Algonquin pipeline’s peak capacity is 3.1 bcf/d for all uses, including “power burn”, per EIA.

https://compressortech2.com/agt-withdraws-ferc-application-for-pipe...

 

Table 6/2035	Prod’n	Prod’n	Gas	Lull	Lull	Lull	Deficit
				15% WS	TWh/d	85% WS
	TWh/y	TWh/d	Bcf/d	TWh/y		TWh/y	TWh/d
Wind + Solar	44.491	0.122		6.674	0.018	37.817	0.104
Offset with gas							0.069
Offset with DM							0.035
Gas, average	50.511	0.138	0.944
Gas, peak	75.738	0.208	1.416
Additional	25.227	0.069	0.472

APPENDIX 1

Cost Shifting is the Name of the Game Regarding Wind and Solar

http://www.windtaskforce.org/profiles/blogs/cost-shifting-is-the-na...

APPENDIX 2

I googled “eurostat, household electric rates, c/kWh, in 2018, by nation”

I got this URL

https://ec.europa.eu/eurostat/statistics-explained/index.php/Electr...

 

Click on “Electricity prices for household consumers”. You will get these graphs. Prices are in euros; 1 euro = $1.117

 

APPENDIX 3

PV solar and wind have significant operational CO2/kWh, on an A to Z basis, from mine/oil well, to decommissioning.

 

Plus there is CO2/kWh embodied in the required infrastructures to make possible the A to Z operational phase.

 

Regarding LNG, there are two CO2 chains.

 

1) The operational CO2/kWh, on an A to Z basis, from gas well/fracking site to users and ultimately decommissioning, i.e., upstream extraction, processing prior to pipeline transport, NG pipeline transport to process plant for additional at harbor site, additional processing of NG prior to liquefaction, NG to LNG liquefaction, LNG storage, transfer to LNG carrier, ship transport to receiving harbor, transfer from ship to LNG storage, trucking of LNG to users, and/or regasifying to NG, feeding NG to existing pipeline system.

 

2) The embodied CO2/kWh for all the infrastructures and their ongoing maintenance, parts replacements to maintain them in proper order, on an A to Z basis, from gas well/fracking site to decommissioning.

 

Items 1 and 2 would each be significantly greater for LNG than for NG.

 

NOTE: According to these sources, 

 

- The upstream CO2 of NG, from gas well/fracking site to users, is about 17% of NG combustion CO2.

https://ceic.tepper.cmu.edu/-/media/files/tepper/centers/ceic/publi...

 

- The upstream CO2 of LNG, from gas well/fracking site to users, is about 43% of NG combustion CO2.

http://www.igu.org/sites/default/files/node-page-field_file/LNGLife...

 

NOTE: Here are some data regarding a part of the costly infrastructure chain for LNG: 

 

- Yamal LNG; operated by Yamal LNG company; owned by Russian independent gas producer Novatek (50.1%), Total, a French company (20%), CNPC (20%) and Silk Road Fund (9.9%); capital cost $27 billion; capacity 16.5 million mt LNG, 3 trains. 

 

- Yamal LNG 2: operated by Yamal LNG company; owned by Novatek (60%), Total (20%); Others (20%); capital cost $25.5 billion; capacity 19.8 million mt LNG, 3 trains.

 

https://www.ft.com/content/56f19604-fd6d-11e7-a492-2c9be7f3120a

https://www.bloomberg.com/news/articles/2017-12-14/russia-dreams-bi...

https://www.total.com/en/media/news/press-releases/yamal-lng-projec...