This post is an overview of the issue of grid reliability as we increase wind and solar. It is mostly based on documents from ISO New England.
ISO New England
The agency responsible for assuring the reliability of electric power in our region is ISO New England. ISO-NE is a non-profit corporation. It has no electric power assets of its own and it is financially tiny compared to the investor owned utilities like Eversource and National Grid.
The first of ISO-NE’s three core missions is to constantly direct the flow of electricity around the region’s high voltage transmission system. ISO-NE’s role is analogous to the role of the Federal Aviation Administration’s air traffic controllers: ISO-NE does not own any assets that generate or transmit power — just as the FAA does not own planes or runways.
We tend not to recognize the power grid as dynamic — we plug in an appliance and expect power to be there. In fact, in every minute of every day, ISO-NE is making decisions to add or subtract generating capacity from the grid and to route power among sub-regions so as to balance load fluctuations.
Since the power market reforms of the 1990s, most generating resources (power plants, wind mills, large solar farms, etc.) are owned by companies independent from the front-end utilities who deliver power to our homes. ISO-NE’s second role is to run a competitive market place in which utilities purchase power from the generators, either in real-time, one day ahead, or as long-term capacity commitments in advance of anticipated need.
The third responsibility of ISO-NE is power system planning: Looking ahead long-term to assure that power generation and transmission capacity will be adequate to meet the region’s energy needs. In this role, ISO-NE has to anticipate and respond to the decisions of both private investors driven by profitability and public policy makers driven by greenhouse gas emission reduction goals. State legislatures across the region are shaping the power markets by mandating a transition to wind and solar (see page 9 of this ISO-NE overview).
Four Pillars of Power Decarbonization
The leadership of ISO-NE has recently been advising legislative policy makers to consider four “pillars” of a successful decarbonization of electric power. (Listen to this podcast, see this presentation, or see this in-depth planning document. For counterpoint and criticism of the ISO, listen to this podcast with Conservation Law Foundation staff.)
- Adequate wind and solar facilities. ISO-NE grades our progress on this pillar with a yellow light — we are making real progress, but not fast enough to meet our stated emission goals. (Compare my similar take here.)
- Adequate transmission lines to accept power from the new renewable facilities. ISO-NE cites a $12 billion regional investment in transmission lines from 2001 to 2021 (see ISO NE Regional System Plan for 2021 at page 99) and grades the region with a green light on this pillar — apparently ahead of the curve for the moment.
- Adequate balancing capacity — generating capacity that can be ramped up or down on a moment’s notice to offset the variability of renewable resources. Wind and solar output is somewhat predictable, and many generators can accelerate and decelerate rapidly. The challenge is not so much technical as financial: If a generator is only going to be needed for a few hours or days in a year, it may not be profitable to keep online. The pricing mechanisms need to be in place to support those generators. On this dimension, ISO-NE grades us at a yellow light trending to red — balancing capacity can currently support renewable growth, but market adjustments may be needed to preserve that capacity
- Assuring energy supply in extreme weather conditions — especially in the winter. On this challenge, ISO-NE is sounding a red-light alarm. If heating need for electricity is high, but the wind is not blowing and the skies are dark, we are currently dependent on fossil-fuel generators, mostly natural gas. Yet, in these conditions, most of the available fracked pipeline gas is taken up by home heating; local gas utilities own long-term supply contracts. So, generators are dependent on spot market purchases of liquid natural gas from foreign countries. (Ironically, under the Jones Act (designed a century ago to protect U.S. shippers), we cannot take LNG shipments from other U.S. ports in a foreign-flagged vessel; and, for cost reasons, all the LNG tankers in the world are foreign-flagged. So by federal law we have to buy LNG from foreign suppliers.) With the Ukranian war on, world LNG prices have soared to the point where it is more cost-effective for us to fire up oil or coal burners — very bad from an emissions perspective and not a very safe backup plan.
Transmission Capacity — More on Second Pillar
An ISO NE study, 2019 Economic Study: Offshore Wind Integration, supports the belief that transmission capacity is not a current limitation of our off-shore wind expansion. The study found that existing south coast transmission lines could accept power from an additional 5800MW of wind capacity (including 1000MW already firmly planned at the time of the study of which 800MW was Massachusetts Vineyard Wind project; Massachusetts now is moving forward on a total of 3200MW of wind). An additional approximately 2200MW of wind capacity could be added either by upgrading south coast connections or by running underwater cables up to the interconnection point currently used by the Mystic power plant near Boston. These options appear very roughly comparable in cost — about $1 billion or more per 1200MW.
The illustration below, taken from page 6 of the study, shows the interconnection points.
Up to the 6000MW level of new wind power, the study finds that not only would transmission capacity be adequate, but spillage of power resources would be limited and significant carbon and cost savings would be realized. As additional wind capacity is added, it may lead to more energy spillage, especially in the shoulder seasons when wind production is highest and demand is lowest. A second ISO-NE Study, 2019 Economic Study: Significant Offshore Wind Integration looked at adding additional wind capacity, running from the 8000MW to 12000MW range; the second study highlights the shoulder season mismatch and also finds a 24 hour cycle mismatch: Wind power is strongest at night when electric demand is lowest. At 12000MW of additional wind capacity, the second study found that so much wind power was spilled that carbon emissions were not reduced materially below the 8000MW scenario.
While we may have an acceptable regional transmission scenario through 2030, it is clear that transmission becomes overloaded as we move towards a fuller decarbonization scenario in 2050. Currently Massachusetts’ Energy Pathways analysis (p.78) calls for 15000MW of installed offshore wind in Massachusetts alone. The Pathways analysis does not appear to fully evaluate the cost, spillage, and transmission load issues raised by the 2019 ISO-NE studies; these issues will only become more salient at higher wind capacity levels. A 2022 study by ISO-NE does address the issue of 2050 transmission load and finds that half of New England’s 9000 miles of transmission lines and a majority of the region’s 150 transformers would be overloaded by planned renewable development in 2050. As of this writing in April 2022, the cost of the necessary upgrades have not been evaluated.
Available Power Mix vs. Used Power Mix — More on Third Pillar
As we think about how much and what kind of electricity we use, the fundamental distinction to bear in mind is between (a) available instantaneous power measured in watts (or kilowatts, megawatts, or gigawatts — thousands, millions, or billions of watts) and (b) power used over time measured in watt-hours (or Wh or KWh or MWh or GWh). A 100 watt light bulb uses 100 watts instantaneously; a 100 watt light bulb left on for ten hours consumes 1000 watt-hours or one KWh.
From the perspective of grid reliability, the question is whether we will have enough power supply to consistently meet instantaneous demand — measured in watts (or megawatts, MW): We have to cover a summer air conditioning demand peak and a winter heating demand peak and we have to cover periods when wind and/or solar are unavailable due to low light and wind conditions.
From the perspective of decarbonization, the question is the fuel source mix for our power generation around all four seasons — measured in watt hours (or megawatt hours, MWh). Fossil resources can play a role in a very thoroughly decarbonized grid if they are used rarely when, due to weather or other conditions, non-fossil resources are inadequate to meet demand. They would have to be able to supply a significant percentage of the MW of power available to the grid, but since they would be rarely dispatched, they could still be only a small percentage of the MWh year-round.
Consistent with this scenario, for the next decade, we will see wind and solar providing a growing share of year-round power, while not much of the committed capacity: The table below shows that in 2021, non-renewable capacity is more than sufficient to meet peak summer demand (barring fuel shortages). In fact from a committed capacity perspective, renewables only cover 0.8% of the peak load capacity for the New England grid. “Behind the meter” roof-top solar is not counted as a grid resource and appears in the reserve computation as a reduction in net demand from the grid (reducing gross peak demand by 836MW or 3% in 2021). However, on a year round basis, wind and solar alone generated a much larger share (6%) of power from industry sources excluding “behind the meter solar” (source: compilation of five New England States from Energy Information Administration State Electricity Profiles for New England States for 2020, Full Datatable 5; see same finding for 2021 in ISO-NE statistical report).
|2021 Summer Peak Forecasts from ISO New England|
|Net Summer Peak Demand (90/10 Probability — 90% chance this level will not be exceeded) <1>||26,711MW|
|Net Summer Peak Demand (50/50 Probability — 50% chance this level will not be exceeded) <1>||24,810MW|
|Summer Generating Capacity Supply Obligations EXCEPT Renewables<2>||29,357MW|
|Import Capacity Supply Obligations||1,208MW|
|Active Demand Capacity Resources (for example, curtail EV charging at peak need)||587MW|
|Total Summer Capacity Excluding Renewables (Generation + Imports + Active Demand)||31,152MW|
|Capacity Reserve Excluding Renewables in 90/10 case (Capacity less 90/10 Net Peak Demand)||4,441MW|
|Capacity Reserve Excluding Renewables in 90/10 case as % of Demand||16.6%|
|Capacity Reserve Excluding Renewables vs 50/50 case (Capacity less 50/50 Net Peak Demand)||6,342MW|
|Capacity Reserve Excluding Renewables in 50/50 case as % of Demand||25.6%|
|Summer Generating Capacity Supply Obligations for Renewables ONLY <2>||247MW|
|Renewables as % of all generating capacity supply obligations||0.8%|
<2> “Renewables” in this table are wind (84MW), grid solar (98MW), batteries (34MW) and fuel cells (31MW).
Source for peak demand estimates: ISO NE 2021 Regional System Plan (page 45):
Source for capacity supply obligations: ISO NE 2021 Forecast Report of Capacity, Energy, Loads and Transmission, Tables 1.1 and 1.3.
Note that Table 1.1 also includes an estimate of Seasonal Claimed Capacity which is slightly higher than the Capacity Supply Obligations.
In the SCC data by generation type, wind and solar show a higher share of seasonal generating capacity — 3.2%;, which makes sense because they are variable and cannot
commit to meet fixed capacity obligations. They still represent much less by this MW metric than by the MWh year round metric.
These computations do not change much over the next ten years according to the ISO-NE forecasts (ISO NE 2021 Forecast Report of Capacity, Energy, Loads and Transmission) because growth of “behind the meter” solar and energy efficiency is expected to offset increased demand for power from electric vehicles and heat pumps.
Summarizing: these numbers confirm the discussion under the third pillar in the previous section — we have the capacity to balance out growing variable wind and solar generation with committed non-renewable resources at least for the next 10 years, provided that non-renewable resources remain supported financially so they remain online as available capacity even if used less and less. In the longer run, if renewable capacity becomes very large, it may be able to cover a larger share of committed capacity even in lower light and wind conditions. Additionally, we may be able to transition the balancing fueled resources to some form of renewable fuel, if the need for them is driven to a low enough level.
For a longer term view recognizing the distinction between the MW reliability perspective and the MWh decarbonization perspective, see Massachusetts Energy Pathways analysis at page 90.
The Winter Challenge — More on the Fourth Pillar
ISO-NE is an expert in balancing supply and demand. If regional power demand exceeds available power supply, they can protect the grid from catastrophic failure by turning off parts of the grid — rolling black-outs. ISO-NE is beginning to warn policy makers that we may need to create a regional natural gas reserve in the medium term or accept an already present risk of rolling black-outs in extreme weather.
Our present risk of rolling blackouts due to gas shortages in extreme weather is not primarily the consequence of our transition to wind and solar. As shown in the charts above and below, wind and solar are a tiny fraction of committed capacity at peak. The fundamental problem today is our increased dependence on natural gas, which has gone from 15% of electricity production to 53% over the past 20 years, with coal, oil and nuclear all declining. At the same time, half our homes are heated with gas. Were natural gas unavailable for purchase in the spot markets at a winter peak, the grid would show a substantial deficit of power, as shown in the last line of the chart below. Of course, the weather risks will grow if power market financial rules allow growing wind capacity to push other capacity permanently off-line.
|2021-22 Winter Peak Forecasts from ISO New England|
|Net Winter Peak Demand (90/10 Probability — 90% chance this level will not be exceeded) <1>||20,349MW|
|Net Winter Peak Demand (50/50 Probability — 50% chance this level will not be exceeded) <1>||19,710MW|
|Winter Generating Capacity Supply Obligations EXCEPT Renewables<2>||29,662MW|
|Import Capacity Supply Obligations||1,135MW|
|Active Demand Capacity Resources (for example, curtail EV charging at peak need)||588MW|
|Total Winter Capacity Excluding Renewables (Generation + Imports + Active Demand)||31,385MW|
|Capacity Reserve Excluding Renewables in 90/10 case (Capacity less 90/10 Net Peak Demand)||11,036MW|
|Capacity Reserve Excluding Renewables in 90/10 case as % of Demand||54.2%|
|Capacity Reserve Excluding Renewables vs 50/50 case (Capacity less 50/50 Net Peak Demand)||11,675MW|
|Capacity Reserve Excluding Renewables in 50/50 case as % of Demand||59.2%|
|Winter Generating Capacity Supply Obligations for Renewables ONLY <2>||316MW|
|Renewables as % of all generating capacity supply obligations||1.1%|
|Winter Generating Capacity Supply Obligations for Natural Gas Only||15,635MW|
|All Winter Generating Capacity Supply Obligations less Natural Gas less 50/50 Peak Demand — DEFICIT||-3,644MW|
<2> “Renewables” in this table are wind (238MW), grid solar (13MW), batteries (34MW) and fuel cells (31MW).
Source for peak demand estimates: ISO NE 2021 Regional System Plan (page 45):
Source for capacity supply obligations: ISO NE 2021 Forecast Report of Capacity, Energy, Loads and Transmission, Tables 1.2 and 1.4.
Note that Table 1.2 also includes an estimate of Seasonal Claimed Capacity which is slightly higher than the Capacity Supply Obligations.
Attractive backup power sources are a long way off. Hydro power from Quebec offers an important capacity increment, but Maine voters setback this approach by voting against the needed transmission line. The project would add 1,200MW of generating capacity to the New England grid. This is a helpful addition, but not transformative: In a truly crippling gas shortage, the table above projects a 3,644MW deficit. ISO-NE is working to better quantify probabilities of events at various levels of shortage so that policy-makers can make informed decisions about what risks to accept.
There is a lot of interest in battery storage, but as of January 2022, Massachusetts only had 320 megawatt hours and our 2025 target is 1000 megawatt hours — 1000 megawatt hours is enough to power Massachusetts for five or 10 minutes. (Massachusetts average year-round rate of electricity consumption was 5,708 megawatts in 2020 with peak consumption much higher.)
Reducing energy consumption through energy efficiency is an important component of the planning process, but so far not such a large component as to eliminate weather risk.
The development of renewable resources, energy efficiency (EE), battery storage, imports, and continued investment in natural gas efficiency measures will help reduce . . . risks, but are unlikely to fully mitigate the risks associated with extreme weather events that limit renewable energy production and/or cause multiple, correlated contingencies. The ISO has initiated a project to update the modeling of low probability, high impact events, including those caused by severe weather. This will allow policy-makers, regulators, and the ISO to assess the likelihood of risks and then discuss whether and how to mitigate these risks.ISO-NE 2021 Regional System Plan, Page 12, November 2, 2021.
With our deep commitment to cutting emissions, the thought of building a natural gas reserve or expanding pipeline capacity is troubling, even if only as a rarely-used backup to increased wind and solar. In its technical planning documents and in its leaders’ statements, ISO-NE is continuing an uncomfortable discussion about present and future risks.
I am working on building my understanding on these issues. I am looking for input and would be grateful for commentary and analysis.