Exploding Duck Curve 2: Renewables Don’t Raise Power Costs – If Penetration Remains Below 80%

Eric Selmon
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Eric Selmon                                                          Hugh Wynne

Office: +1-646-843-7200                                        Office: +1-917-999-8556

Email: eselmon@ssrllc.com                                   Email: hwynne@ssrllc.com

SEE LAST PAGE OF THIS REPORT FOR IMPORTANT DISCLOSURES

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May 6, 2019

Exploding Duck Curve 2: Renewables Don’t Raise Power Costs – If Penetration Remains Below 80%

To supply reliable power generation capacity with intermittent wind and solar resources is prohibitively expensive; were California to transition to a 100% renewable supply of electricity with a degree of reliability comparable to that of California’s power grid today, we estimate the cost of electric energy in the state, before wires charges by the utilities, would quadruple (see our research report Exploding Duck Curve: What Does It Cost to Achieve 100% Renewable Electricity and What Are the Implications?). The cost of renewable energy, by contrast, is low and falling. In this piece, we analyze the cost to supply 80% to 90% of the electricity consumed in California with renewable energy, while continuing to rely on the state’s installed base of dispatchable generation capacity to ensure a reliable supply of electricity during all hours of the year. On this basis, the case for high levels of renewable penetration is compelling: we calculate that 80% of California’s electricity could be supplied from renewable resources at a cost of $54/MWh, comparable to the $53/MWh cost of full requirements power in the state today. At levels of renewable generation above 80%, however, the cost of electricity rises rapidly: at 90% renewable generation, we estimate the cost of full requirements power at $69/MWh, an increase of 30%; at 100% renewables, we estimate the cost at $213 per MWh, an increase of over 300% (see Exhibit 1).

One implication is that renewable energy, at levels of penetration of 80% or less, can be a very low cost means of reducing CO2 emissions. When we compare (i) the increase in the cost of electricity attributable to 80% renewable penetration to (ii) the carbon dioxide emissions avoided as a result, we find the cost of CO2 avoided to be just $3 per metric ton. As renewable penetration rises from 80% to 90%, however, the cost of the incremental CO2 emissions avoided rises to $257 per metric ton (Exhibit 3).

Our analysis demonstrates the economic advantage of depending upon California’s existing fleet of dispatchable power plants to ensure a reliable supply of electricity during all hours of the year, rather than attempting to replicate current levels of reliability with intermittent wind and solar resources backstopped by energy storage. Minimizing the cost of transitioning to high levels of renewable penetration thus implies the need to preserve large portions of California’s existing non-renewable generation capacity. At 80% renewable penetration, California would continue to require ~32 GW of non-renewable generation capacity to ensure reliability, equivalent to 92% of CAISO’s non-renewable capacity today (35 GW) and 124% of its existing simple cycle and combined cycle gas turbine capacity (26 GW) (see Exhibit 7).

While high levels of renewable penetration do not eliminate the need for large amounts of backstop generation capacity, they radically reduce the output of these resources. As a result, we expect the average capacity factor of California’s backstop generation to fall to levels typical of peaking plants today (see Exhibit 9). As California transitions to higher levels of renewable penetration, therefore, mobilizing the capital to build both renewable and backstop generation capacity will require long term PPAs with creditworthy counterparties, or the inclusion of these assets in the rate base of regulated utilities. Yet California’s ability to support capacity additions with creditworthy PPAs has diminished as the responsibility for power procurement has been fragmented among utilities, community choice aggregators and other retail electricity suppliers. The state’s utilities have also suffered a marked erosion in credit quality caused by rising wildfire risk and the bankruptcy of PG&E. This suggests that a centralized, state-backed power procurement agency could be the lowest cost method of procuring the capacity to meet California’s renewable energy targets while safeguarding the reliability of its power system.

Portfolio Manager’s Summary

  • Given our assumption that California maintains access to its existing, dispatchable generation resources, the lowest cost mix of wind, solar and energy storage capable of supplying 80% of the state’s electricity demand comprises 25 GW of wind capacity, 25 GW of solar capacity and 2.5 GW of storage capacity (equivalent to 10 GWh, given the typical four hour duration of discharge of lithium ion batteries). These requirements compare with a current installed fleet of 9.2 GW of wind, 13.8 GW of solar and 0.2 GWh of installed energy storage.
  • The aggregate cost of these wind, solar and storage resources, based on their current construction cost, plus the market value of the fossil, hydroelectric and geothermal generation that we estimate California will use, is equivalent to $54 per MWh supplied. This compares with an average around-the-clock price for full requirements electricity[1] in California of $53/MWh in 2018 (see Exhibit 1).
  • The very low incremental cost of renewable generation renders it a highly economic means of reducing carbon dioxide emissions. California’s fossil fired generating fleet, which is predominantly gas fired, emits an average of 0.49 metric tons of carbon dioxide per MWh produced. In a scenario where 80% of California’s power demand is supplied by renewable resources, the need for fossil fired generation is reduced by some 54 million MWh, with a corresponding reduction in CO2 emissions of 26 million metric tons.
    • Given the very low incremental cost of supplying electricity in this scenario (an average of $54/MWh as against a full requirements price of $53/MWh today), we calculate the cost of this reduction in CO2 emissions at only $3 per metric ton (see Exhibit 2).
  • At levels of renewable penetration above 80%, however, the cost of electricity rises rapidly.
    • As levels of renewable penetration approach 100%, it becomes necessary to supply renewable energy to meet demand even during hours when wind and solar output is low. Substantial shortfalls of renewable generation can occur on windless nights and winter days, when days are short, the sun is low in the sky, and cloud cover can suppress solar output.
    • To ensure renewable generation is sufficient to meet demand during such hours, a substantial investment in storage capacity is required. To charge these battery banks, moreover, the installed base of wind and solar capacity must be increased as well.[2]
  • As a result, at 90% renewable generation, the cost of full requirements power in California rises from $53/MWh today to $69/MWh, well above our estimate of $54/MWh in our 80% scenario.
    • The cost increase relative to our 80% scenario reflects the need to increase California’s energy storage capacity from 2.5 GW to 12.5 GW and, to charge this larger fleet of batteries, to increase California’s solar generation capacity from 25 GW to 30 GW and its wind generation capacity from 25 GW to 40 GW (see Exhibit 5).
  • To achieve 100% renewable penetration, where renewable generation is available to meet the state’s electricity demand during every hour of the year, the cost of electricity quadruples, from $53/MWh today to $213/MWh (see Exhibit 1). Spread across CAISO’s 230 million MWh of annual electricity demand, this increase in the cost of electricity represents an enormous economic burden on the state, equivalent to some $29 billion annually.
    • The cost increase relative to our 90% scenario reflects the need to increase California’s energy storage capacity from 12.5 GW to 177.5 GW and, to charge this much larger fleet of batteries, to increase California’s wind and solar generation capacity from 70 GW to 265 GW (see Exhibit 5).
  • The rapid escalation in the cost of supplying full requirements electricity once renewable penetration exceeds 80% raises the question of whether further increases in renewable penetration are the most cost effective means to reduce CO2 emissions.
    • We estimate that achieving 90% renewable penetration would reduce California’s fossil fuel generation by 76 million MWh, cutting the state’s CO2 emissions by 37 million metric tons. The average cost of CO2 emissions avoided, however, would rise to $77 per ton. More importantly, as renewable penetration rises from 80% to 90%, the incremental cost of CO2 emissions reductions hits $257 per metric ton. (See Exhibits 2 and 3).
    • A 100% renewable system would achieve a reduction of 99 million MWh in fossil fuel generation, cutting CO2 emissions by 49 million tons. In the 100% scenario, the average cost of CO2 emissions avoided rises to some $600 per metric ton. The incremental cost to curtail CO2 emissions rises even more rapidly, exceeding $2,300 per metric ton as renewable penetration rises from 90% to 100%.
  • Incurring these costs as a means of reducing CO2 emissions is not economically efficient.
    • The price of CO2 emissions allowances in California is only $15 per metric ton, suggesting that far less costly means of reducing CO2 emissions are currently available.
    • Moreover, the U.S. EPA has estimated the social cost of carbon dioxide emissions, assuming a 3% real discount rate, to be $42 per metric ton in 2020 and $69 per metric ton in 2050. To incur costs to reduce CO2 emissions that exceed these levels has a negative social impact.
  • A lower cost means of reducing CO2 emissions, as well as other air pollutants, might be to increase the electrification of the Californian vehicle fleet, capitalizing on the very low levels of CO2 emissions of a power system 80% supplied by renewable energy.
    • The CO2 emissions avoided by raising renewable penetration from 80% to 90%, or 90% to 100%, of California’s electricity demand are equivalent to the CO2 emissions avoided by electrifying 6% of California’s 30 million fleet of light and heavy duty vehicles.[3]
  • Our analysis demonstrates the economic advantage of depending upon California’s existing fleet of dispatchable power plants to ensure a reliable supply of electricity during all hours of the year, rather than attempting to replicate current levels of reliability with intermittent wind and solar resources backstopped by energy storage.
  • Minimizing the cost of transitioning to high levels of renewable penetration thus implies the need to preserve large portions of California’s existing non-renewable generation capacity. At 80% renewable penetration, California would continue to require ~32 GW of non-renewable generation capacity to ensure reliability, equivalent to 92% of CAISO’s non-renewable capacity today (35 GW) and 124% of its existing simple cycle and combined cycle gas turbine capacity (26 GW) (Exhibit 7).
    • High levels of renewable penetration do not eliminate the need for large amounts of backstop generation capacity; they do, however, radically reduce the output of these resources. As a result, we expect the average capacity factor of California’s backstop generation to fall to levels typical of peaking plants today (see Exhibit 9).
      • Like peaking plants today, therefore, existing capacity will require capacity payments through the resource adequacy market to ensure they generate enough cash flow to stay online.
      • Moreover, the new backstop generation resources required to maintain system reliability will need to be supported either (i) by long term power purchase agreements capable of ensuring the return of and on invested capital, or (ii) through the inclusion of these assets in the rate base of regulated utilities, whose cost-of-service-based rates would achieve a similar result.
  • Ensuring an economic return on new renewable generation resources, as well the new backstop capacity required to support these renewable resources, will be a policy challenge for the state.
  • California’s ability to support additions of renewable and backstop generation capacity with creditworthy PPAs has eroded as the responsibility for power procurement has fragmented among utilities, community choice aggregators and other retail electricity suppliers.
  • The state’s utilities have also suffered a marked deterioration in credit quality caused by rising wildfire risk and the bankruptcy of PG&E.
  • This suggests that a centralized, state-backed power procurement agency could be the lowest cost method of procuring the capacity to meet California’s renewable energy targets while safeguarding the reliability of its power system.

Details

The Objectives, Constraints and Methodology of Our Analysis

In 2018, over 40% of the electricity supplied in California was generated by renewable resources. California law requires that the share of renewable energy rise to 60% by 2030, and that by 2045 all the state’s electricity come from carbon-free sources.  In this research report, we assess the scale and cost of the renewable resources required to generate 80%, 90% and 100% of California’s total electricity demand, with a degree of reliability comparable to that of California’s power grid today.

Using software developed by MADA Analytics, the MADA Energy Processing Solution (MEPS), our model determines the least costly mix of California’s various renewable resources that would meet these target levels of renewable penetration.[4] It does so while respecting a key constraint, that power supply and power demand on the gird be balanced at all times. This continuous equivalence of power supply and demand is required to ensure that voltage levels on the grid remain within the narrow tolerance band of the electrical equipment and devices powered by the grid. An excess of power supply over demand can raise voltages to levels that damage or destroy this equipment, while an excess of demand over supply can lead to brownouts and blackouts.

In assessing the cost of various levels of renewable penetration, therefore, our model seeks to ensure that in each scenario the generation and storage resources on the grid are capable of supplying the demand for electricity in every hour of the year. Specifically, our model balances California’s demand for electricity in each hour of 2017 (hourly load in kW), with:

  1. the output of a hypothetical fleet of wind and solar resources which, added to California’s existing hydroelectric and geothermal capacity, is adequate to supply the desired level of renewable energy, complemented by
  2. expanded energy storage capacity to capture excess renewable generation for later use, and supplemented by
  3. the output of the state’s existing fleet of nuclear and fossil fuel generation capacity, which can be relied upon to ensure a supply of electricity even during prolonged periods of low renewable output.

(An analysis of how the need to balance prevailing power demand with limited renewable generation drives the resource requirements of the grid is available on page 3 of our research report of April 1st, Exploding Duck Curve: What Does It Cost to Achieve 100% Renewable Electricity and What Are the Implications?.)

In each of the scenarios modeled – 80%, 90% and 100% renewable penetration — the wind, solar and storage capacity required to meet these targets far exceed California’s installed capacity of these resources. Given the need for massive capacity additions, our analysis estimates the cost to build new facilities as well as the cost to operate and maintain them.

Specifically, we have estimated the current levelized cost of energy (LCOE)[5] from new wind, solar, and storage resources and imputed these costs to the wind, solar and storage capacity required to meet the target levels of renewable generation. We have based our estimates of the capital and operating costs of new wind, solar and energy storage resources on Lazard’s Levelized Cost of Energy Analysis – Version 12.0 and Lazard’s Levelized Cost of Storage Analysis – Version 4.0. To forecast the output of these new wind and solar generation assets, our model uses the hourly output in 2017 of recent vintage wind and solar resources in typical locations in California (Tehachapi Pass for wind and Los Angeles County for solar). Finally, we have designed this hypothetical renewable fleet and associated energy storage so as to minimize the cost of meeting the target level of renewable penetration.

Because we do not anticipate an expansion of California’s existing nuclear, fossil fuel, hydroelectric and geothermal capacity, we have not estimated the cost of energy from these resources on the basis of new-build economics, as we have for wind and solar. Rather, we impute a cost to existing conventional generation equal to the around-the-clock price of wholesale power on the California ISO (CAISO) in 2017. Finally, we estimate the output of California’s existing hydroelectric and geothermal power plants based upon the long historical track record of these resources: our analysis assumes that the volume of California’s hydroelectric and geothermal generation will equal the average monthly output of these resources over the last 20 years.

Results: The Price of Electricity and the Cost of Reducing CO2 Emissions

Assuming that California maintains access to its existing, dispatchable generation resources, the lowest cost mix of wind, solar and energy storage capable of supplying 80% of the state’s electricity demand comprises 25 GW of wind capacity, 25 GW of solar capacity and 2.5 GW of storage capacity (equivalent to 10 GWh, given the typical four hour duration of discharge of lithium ion batteries). These requirements compare with a current installed fleet of 9.2 GW of wind, 13.8 GW of solar and 0.2 GWh of installed energy storage.

The aggregate cost of these wind, solar and storage resources, based on their current construction cost, plus the market value of the nuclear, fossil, hydroelectric and geothermal generation that we estimate California will use, is equivalent to $54 per MWh. This compares with an average around-the-clock price for full requirements electricity[6] in the state of $53/MWh in 2018 (see Exhibit 1).

Exhibit 1: We estimate the system levelized cost of energy, assuming 80% renewables, to be similar to today’s price for full requirements power

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Source: MADA Analytics, Lazard’s Levelized Cost of Energy and Levelized Cost of Storage 2018, S&P Global, SSR analysis

The very low incremental cost of renewable generation renders it a highly economic means of reducing carbon dioxide emissions. California’s fossil fired generating fleet, which is predominantly gas fired, emits an average of 0.49 metric tons of carbon dioxide per MWh produced. Our modeling finds that, in a scenario where 80% of California’s power demand is supplied by renewable resources, the need for fossil fired generation is reduced by some 54 million MWh, with a corresponding reduction in CO2 emissions of 26 million metric tons. The low incremental cost of supplying the requisite renewable energy (resulting in an average system price of power of $54/MWh, as against a full requirements price of $53/MWh today), translates into an annual increase in the cost of electricity to the state of only $68 million. On this basis, we calculate the cost of this 26 million metric ton reduction in CO2 emissions to be ~$2.60/metric ton (see Exhibit 2). [7]

Exhibit 2: Average Cost per Metric Ton of Exhibit 3: Incremental Cost per Metric Ton of CO2 Avoided CO2 Avoided

 

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Source: MADA Analytics, Lazard’s Levelized Cost of Energy and Levelized Cost of Storage 2018, S&P Global, SSR analysis

At levels of renewable penetration above 80%, our modeling finds that the cost of electricity rises rapidly. California’s abundant renewable resources are capable of meeting 80% of the state’s energy demand with a small amount of energy storage (2.5 GW or 10 GWh), reflecting the relatively high number of hours when electricity demand and renewable generation coincide. As levels of renewable penetration approach 100%, however, it becomes necessary to supply renewable energy to meet demand even during those hours when the state’s wind and solar output is low. These conditions can occur on windless nights and during daylight hours in the winter months, when days are short, the sun is low in the sky, and rain or cloud cover can further suppress solar output.

To ensure renewable generation is sufficient to meet demand during prolonged periods of low wind and solar output, a substantial investment in storage capacity is required. As this storage capacity much be charged with renewable generation in excess of that required to meet prevailing electricity demand, the installed base of wind and solar capacity must be increased as well.[8] The transition from 80% to 90% renewable generation thus requires an increase in California’s energy storage capacity from 2.5 GW to 12.5 GW and, to charge this larger fleet of batteries, an increase in California’s solar generation capacity from 25 GW to 30 GW and an increase in its wind generation capacity from 25 GW to 40 GW (see Exhibit 5). As a result, we estimate the cost of full requirements power in California rises to $69/MWh, some 30% above our estimate of the average 2018 full requirements price of $53/MWh and our estimate of $54/MWh in an 80% renewable penetration scenario.

Exhibit 4: Total Wind, Solar & Storage Capacity Required at Different Levels Of Renewable Penetration (GW)                                         

Exhibit 5: Lowest Cost Combination of Wind, Solar & Storage Resources at Different Levels Of Renewable Penetration (GW)

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Source: MADA Analytics, Lazard’s Levelized Cost of Energy and Levelized Cost of Storage 2018, S&P Global, SSR analysis

To increase renewable penetration from 90% to 100%, while ensuring a reliable supply of electricity during every hour of the year, it becomes necessary to bridge the very longest periods of low renewable output with increased battery capacity — not the relatively short periods of low renewable generation occurring, for example, on windless summer nights, but prolonged periods comprising several days of low wind and solar output. As noted above, these periods tend to occur during the winter months, when days are short, the sun is low in the sky, and rain or cloud cover can suppress solar output for several days in a row. In January 2017, these conditions combined with a series of windless nights to cause a five day period of low renewable generation.

As a result, to achieve 100% renewable penetration, the cost of full requirements power quadruples, from $53/MWh in 2018 to $213/MWh (see Exhibit 1). The cost increase relative to our 90% scenario reflects the need to increase California’s energy storage capacity from 12.5 GW to 177.5 GW and, to charge this larger fleet of batteries, to increase California’s wind and solar generation capacity from 70 GW to 265 GW (see Exhibit 5). Spread across California’s 230 million MWh of annual electricity demand, this cost increase places an economic burden on the state of some $29 billion in additional electricity costs annually.

The rapid escalation in the cost of supplying full requirements electricity once renewable penetration exceeds 80% raises the question of whether further increases in renewable penetration are the most cost effective means to reduce CO2 emissions. We estimate that achieving 90% renewable penetration would allow California to decrease its dependence on fossil fuel generation by 76 million MWh, cutting CO2 emissions by a total of 37 million metric tons annually. The average cost of CO2 emissions avoided, however, would rise to $77 per metric ton. More importantly, as renewable penetration increases from 80% to 90%, the incremental cost of CO2 emissions reductions hits $257 per metric ton. (See Exhibits 2 and 3.) A 100% renewable system would reduce fossil fuel generation by 99 million MWh, cutting CO2 emissions by a total of 49 million tons annually. Yet in the 100% scenario, the average cost of CO2 emissions avoided rises to some $600 per metric ton. The incremental cost to curtail CO2 emissions reductions, as renewable penetration rises from 90% to 100%, exceeds $2,300 per metric ton.

By comparison, the price of CO2 emissions allowances in California is only $15 per metric ton, suggesting that far less costly means of reducing CO2 emissions are currently available. Moreover, the U.S. EPA has estimated the social cost of carbon dioxide emissions, assuming a 3% real discount rate, to be $42 per metric ton in 2020 and $69 per metric ton in 2050. To incur costs to reduce CO2 emissions that exceed these levels has a negative social impact. Californians would be better off funding lower cost emissions reductions in other states or countries rather than trying to achieve higher levels of renewables penetration.

One lower cost means of reducing CO2 emissions, as well as other air pollutants, might be to increase the electrification of the Californian vehicle fleet, capitalizing on the very low levels of CO2 emissions of a power system 80% supplied by renewable energy. The CO2 emissions avoided by raising renewable penetration from 80% to 90%, or 90% to 100%, of California’s electricity demand are equivalent to the CO2 emissions avoided by electrifying 6% of California’s 30 million fleet of light and heavy duty vehicles.[9]

We expect the cost of transitioning to higher levels of renewable penetration to decline over time as the installed cost of wind, solar and storage resources falls and the energy efficiency of these resources increases. To quantify this effect, we have compared the cost of building the wind, solar and storage resources required to meet 80%, 90% and 100% renewable penetration based upon the estimated cost of these resources in 2019, 2025 and 2030. Based on recent trends, we assumed that the installed cost of new battery, solar and wind capacity would fall at compound annual rates of 8.5%, 7.0% and 3.0%, respectively, through 2025 and at 5.0%, 3.5% and 1.0% annually thereafter.

At low levels of renewable penetration, the aggregate impact of these cost declines is relatively modest. In the 80% renewables scenario, we calculate the cost of electricity will fall from $54/MWh, based on our estimates of the 2019 LCOEs of wind, solar and storage, to $44/MWh by 2030 (see Exhibit 6); in the 90% renewables scenario, we estimate that the cost of electricity will decline from $69/MWh in 2019 to $52/MWh in 2030. In our 100% renewables scenario, by contrast, the enormous scale of the generation and storage resources required implies that any decline in the cost of these resources has a much greater impact. In this scenario, we estimate the cost of electricity falls from $213/MWh in 2019 to $127/MWh in 2030. Compared to the $53/MWh cost of full requirements electricity today, however, this still represents an increase of $74/MWh, or an incremental cost of $17 billion annually for the state’s electricity consumers.

Exhibit 6: We expect the system LCOE to fall significantly over time, with the greatest impact on high renewable penetration scenarios

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Source: MADA Analytics, Lazard’s Levelized Cost of Energy and Levelized Cost of Storage 2018, S&P Global, SSR analysis

Results: The Implications for California’s Non-Renewable Power Generation Capacity

The above analysis demonstrates the economic advantage of depending upon California’s existing fleet of nuclear and fossil fuel power plants to ensure a reliable supply of electricity during all hours of the year, rather than attempting to replicate current levels of reliability using intermittent wind and solar resources backstopped by energy storage. The economic benefit of conventional, dispatchable power plants will only become clearer as the state struggles with the rapidly rising incremental cost of supplying fully reliable power solely from intermittent wind and solar resources.

Even at very high levels of renewable penetration, the difficulty of ensuring an adequate supply of renewable energy to meet demand during every hour of the year implies the need for a surprisingly large amount of non-renewable, dispatchable capacity. A comparison of California’s hourly demand for electricity in 2017 with the hourly output of the state’s renewable generation resources shows that, even at 80% renewable penetration, the excess of demand over available renewable generation and storage capacity can be as high as 32 GW. At 90% renewable penetration, the estimated maximum hourly excess of demand over the supply of renewable energy is still 31 GW. Shortfalls of this magnitude occur during several hours throughout the year in both these scenarios.

Exhibit 7 compares the scale of the 2017 shortfalls to the non-renewable generation capacity currently available in the state of California. As can be seen there, covering a shortfall of renewable generation relative to demand of 32 GW requires the output of 92% of California’s existing non-renewable generation capacity. Yet large portions of California’s existing non-renewable generating fleet are being phased out as a result of increasingly stringent environmental regulations governing the intake of cooling water required by steam turbine generating plants. California’s 2.25 GW of nuclear generation capacity will be fully retired by 2025; by that year, over 4.0 GW of existing fossil fuel steam turbine capacity is expected to be retired as well.

Over time, therefore, California will become increasingly reliant on its fleet of simple and combined cycle gas turbine generators to bridge future shortfalls between available renewable generation and the level of demand prevailing on the grid. California’s 26 GW gas turbine fleet, however, is insufficient to bridge the 32 GW shortfall evident in the 2017 data (see Exhibit 7). This suggests that California will need to build additional gas turbine capacity, or procure commitments of such capacity from other states, to offset the loss of an estimated 6 GW of nuclear and fossil fuel steam turbine capacity by 2025.

Exhibit 7: Backstop Dispatchable Capacity Required, in GW and as % of California’s 2019 Installed Capacity

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Source: MADA Analytics, Lazard’s Levelized Cost of Energy and Levelized Cost of Storage 2018, S&P Global, SSR analysis

Exhibit 8: Technology Breakdown of Existing CAISO Generation Capacity

Generation Resources by Technology                          

 

Renewable v. Non-Renewable Capacity (GW)

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Source: S&P Global, SSR analysis

Ensuring an economic return on these backstop generation resources, and providing an economic incentive to add additional backstop capacity over time, will be a policy challenge for the state. As we have seen, high levels of renewable penetration do not eliminate the need for large amounts of backstop generation capacity; they do, however, radically reduce the output of these resources. As a result, we expect the average capacity factor of California’s backstop generation to fall to levels typical of peaking plants today (see Exhibit 9). Like peaking plants today, therefore, existing capacity will require capacity payments through the resource adequacy market or another mechanism to ensure they generate enough cash flow to stay online. However, new backstop generation resources required to maintain system reliability will need to be supported either (i) by long term power purchase agreements capable of ensuring the return of and on invested capital, or (ii) through the inclusion of these assets in the rate base of regulated utilities, whose cost-of-service-based rates would achieve a similar result.

Exhibit 9: Expected Capacity Factor of the Backstop Dispatchable Capacity Required in Various Renewable Penetration Scenarios

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Source: MADA Analytics, Lazard’s Levelized Cost of Energy and Levelized Cost of Storage 2018, S&P Global, SSR analysis

In summary, one of the primary conclusions of our analysis is that California will find it economic to continue to depend upon its existing non-renewable generation capacity to ensure a reliable supply of electricity during each hour of the year. The combination of high renewable penetration rates and the continued need for substantial backstop generation capacity will drive the average capacity factor of these resources down to levels where they would be uneconomic to build on a merchant basis. Future additions of backstop generation capacity, similar to the future additions of renewable generation and storage, will therefore need to be included in the rate base of regulated utilities or supported by long term PPAs.

Yet California’s ability to support capacity additions with creditworthy PPAs has eroded as the responsibility for power procurement has fragmented among utilities, community choice aggregators and other retail electricity suppliers. The state’s utilities have also suffered a marked deterioration in credit quality caused by rising wildfire risk and the bankruptcy of PG&E. This suggests that a centralized, state-backed power procurement agency could be the lowest cost method of procuring the capacity to meet California’s renewable energy targets while safeguarding the reliability of its power system.

Results: California’s Excess Renewable Generation and the Western Power Market

A power system designed to ensure a reliable supply of renewable energy even during prolonged periods of low wind and solar output is necessarily one that is capable of generating much higher amounts of electricity when conditions are at their best, such as during long, sunny summer days. The scale of renewable generation and storage capacity that is just sufficient to meet demand during the worst days of the year is massively oversized for the rest. The higher the level of renewable penetration targeted, therefore, the higher the level of excess renewable energy the system will produce.

The charts below illustrate the scale of excess renewable generation in California at different levels of renewable penetration. As can be seen there, a target of 80% renewable energy can be achieved with a relatively small amount of excess renewable generation: 30 million MWh (see Exhibit 10). If exported, this excess would be equivalent to 10% of the annual electricity demand of the surrounding states (Oregon, Washington, Idaho, Nevada, Utah and Arizona) (see Exhibit 11). The impact on western power markets will likely be greater than this, however; California currently imports ~56 million MWh of non-renewable energy from the surrounding states, equal to ~18% of these states’ demand. These imports are sure to decline dramatically and eventually to disappear as California transitions to higher levels of renewable penetration.

Exhibit 10: California’s Excess Renewable Generation in Millions of MWh per Year1

Exhibit 11: California’s Excess Renewable Generation as % of Surrounding States’ Demand2

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1. Output of California’s renewable resources in excess of Californian electricity consumption and storage capacity.

2. Regional demand includes all power consumption of Oregon, Washington, Idaho, Nevada, Utah and Arizona.

Source: MADA Analytics, Lazard’s Levelized Cost of Energy and Levelized Cost of Storage 2018, S&P Global, SSR analysis.

At higher levels of renewable penetration, the picture changes dramatically. A system capable of supplying 90% of California’s power demand with renewable energy would produce over 90 million MWh of excess renewable energy, equivalent to 30% of the demand of the surrounding states. A system capable of supplying 100% of California’s power demand with renewable energy would produce over 307 million MWh of excess energy, equivalent to 100% of the demand of the surrounding states.

To assess the impact of high levels of renewable penetration on the wholesale power market, however, the frequency of the excess renewable generation is as important as its scale. In Exhibit 12, therefore, we present the monthly excess of (i) the output of California’s renewable resources over (ii) the sum of Californian electricity consumption and storage capacity, expressed as a percentage of the monthly electricity demand in the surrounding states (Oregon, Washington, Idaho, Nevada, Utah and Arizona). As can be seen there, at 90% renewable penetration, California’s excess generation would be equivalent to over third of power demand in the surrounding states during six months of the year. At 100% renewable penetration, California’s excess generation could supply 95% or more of the demand in the surrounding states during eight months of the year.

These levels of renewable penetration may be achieved over the next 25 years: California’s Senate Bill 100, signed into law in 2018, increases the state’s renewable portfolio standard to 60% by 2030 and requires all the state’s electricity to come from carbon-free resources by 2045.

It is inevitable, given the volume and frequency of the excess renewable generation available from California, that wholesale power prices in California and surrounding states will be subject to significant downward pressure. In particular, if California were to achieve 100% renewable penetration, it is unlikely that western power markets could sustain prices far enough above zero for a sufficient number of hours each year to incent the construction of new merchant generation capacity. California’s commitment to achieve 100% carbon-free generation by 2045, if achieved, would likely render new merchant generation uneconomic in the entire region. As in California, the construction of backstop capacity in these states would also need to be supported by PPAs or included in the rate base of regulated utilities.

Exhibit 12: California’s Excess Renewable Generation Expressed as a Percentage of the Total Monthly Electricity Demand in Surrounding States1

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1. Output of California’s renewable resources in excess of Californian electricity consumption and storage capacity compared to the combined monthly electricity consumption of Oregon, Washington, Idaho, Nevada, Utah and Arizona.

Source: MADA Analytics, Lazard’s Levelized Cost of Energy and Levelized Cost of Storage 2018, S&P Global, SSR analysis

Exhibit 13: Heat Map: Preferences Among Utilities, IPP and Clean Technology

Source: SSR analysis

Appendix: Software and Inputs

The Software

The modelling software we used to perform our analysis is MADA Energy Processing Solutions (MEPS), and was developed by MADA Analytics, a data-analytics energy-storage software company, of which Eric Selmon is a co-founder, shareholder and director. MEPS is designed to optimize combinations of various renewable generating technologies with energy storage to achieve a defined goal (usually highest return or lowest cost). It does so by conducting an hourly analysis of all of the different possible combinations of the generation and storage technologies within a user-set range, and calculating the power output, performance and financial results of each combination across all of the hours over the life of the projects.

For this analysis, we assumed that only solar, wind and battery storage, plus existing hydroelectric, geothermal and biomass generation, would be used to meet demand.  We optimized for the lowest cost combination of these resources that was able to meet system demand in every hour of the year. We also ran an alternative scenario where renewables supply only 99.9% of demand, allowing us to quantify the impact on cost as the targets for renewable penetration decrease, as well as the dispatchable peaking capacity (i.e. gas fired peakers) required for system reliability as renewable targets fall.

Critically, MEPS’ focus on the balance between hourly supply and demand provides allows for a much more accurate result than an analysis that uses only the aggregate annual or monthly data on peak demand and resource availability, because it addresses the fundamental need of the power grid to match supply and demand at all times. Based on the hourly output of typical wind and solar resources in California in 2017, and CAISO’s hourly load in that year, we were able to identify those hours of the year when the system was most vulnerable to a shortfall of supply as a result of prolonged periods of low renewable generation, resulting in the full discharge of the system’s battery storage capacity.

MEPS can also incorporate the cost of conventional generation capacity to backstop the supply from intermittent renewable resources. As discussed in the body of this research report, the output of a system designed to meet 99.9% California’s power demand with renewable energy would have fallen short of demand for 20 hours in 2017. MEPS allow us to design the lowest cost solution to offset this gap (using gas fired generation to meet the shortfall in supply during these 20 hours), and to calculate an adjusted LCOE that includes the cost of these additional resources.

 

Hourly Data Inputs

 

To operate, the MADA software requires hourly data on solar insolation, windspeed and demand for each location. While the software can handle tremendous levels of complexity, we used an Excel-based pilot version of the software, so the time to run each simulation increased greatly with the complexity. Therefore, to simplify the analysis, we used data for solar insolation and windspeed from a single, typical location (Tehachapi Pass for wind and LA for solar) and we used only a single year of data (2017) for the solar, wind and demand data.

To account for the availability of existing hydroelectric, geothermal and biomass generation, we reduced the hourly demand required to be met by the wind, solar and storage resources in the model by the average hourly hydro and geothermal output since 2000, and average hourly biomass over the most recent full year, 2017.

Possible Biases in the Data

Using a single location and year to estimate the volatility of renewable generation, and a single year to estimate the volatility of system load, may introduce distortions in our analysis.

In particular, measuring solar and wind generation at a single location will tend to underestimate the stability of the state-wide supply of renewable energy, thus causing the model to overestimate the scale of solar and wind resources required to meet demand during every hour of the year. That said, using a single location and year to estimate the amount of hourly solar generation should have only a limited impact on the results of our analysis, as solar insolation does not vary much in California from year to year, nor is there high regional variation across the state during any given hour. By contrast, windspeeds can vary significantly from year to year and are very location specific. Relying on windspeed data from just the Tehachapi Pass, therefore, likely underestimates the stability of the California’s total wind output from hour to hour and therefore overestimates the resources required to meet demand. However, because weather fronts, which drive the general presence or absence of wind at any time, cover large areas, we believe the impact is limited.

Importantly, other assumptions used in our analysis will tend to understate the resources required to meet demand during each hour of the year, thus introducing a contrary bias. Our use of a long term average for hydroelectric generation means that we have not accounted for the full impact of drought conditions, which would require additional resources to offset. Critically, also, our use of a single year of demand data tends to underestimate the volatility of demand, again causing our model to underestimate the need for generation and storage resources.

Finally, given the enormous scale and cost of the renewable and storage resources required to meet hourly demand, we are confident that the overall conclusions of our analysis are robust despite the potential biases in the data.

©2019, SSR LLC, 225 High Ridge Road, Stamford, CT 06905. All rights reserved. The information contained in this report has been obtained from sources believed to be reliable, and its accuracy and completeness is not guaranteed. No representation or warranty, express or implied, is made as to the fairness, accuracy, completeness or correctness of the information and opinions contained herein.  The views and other information provided are subject to change without notice.  This report is issued without regard to the specific investment objectives, financial situation or particular needs of any specific recipient and is not construed as a solicitation or an offer to buy or sell any securities or related financial instruments. Past performance is not necessarily a guide to future results.

  1. The full requirements price of electricity is the price sufficient to pay for the resources required to supply 100% of the electricity demand prevailing during each hour of the year. It includes the cost of energy, capacity, and ancillary services.

    It does not include the charges for transmission and distribution by the electric utilities. 

  2. For a detailed analysis on this problem, based on actual 2017 hourly data, please see our research report of April 1st,Exploding Duck Curve: What Does It Cost to Achieve 100% Renewable Electricity and What Are the Implications?
  3. To illustrate the huge cost of high levels of renewable penetration, the 11.4 million metric tons of CO2 avoided by raising California’s renewable penetration from 90% to 100% would increase the state’s electricity bill by some $26 billion per year. The state of California could save $8 billion a year, while achieving a similar reduction in CO2, by leasing 4.3 million Nissan Leafs and giving them away for free to new car buyers in lieu of internal combustion vehicles. 
  4. Please see the Appendix to this research report for more information on the MADA software and our model. 
  5. The levelized cost of energy is expressed in $/MWh and equals (i) the annual cash cost to build and operate a power plant, discounted back to the present, divided by (ii) the annual energy output of the plant over its useful life, also discounted back to the present. The LCOE can be regarded as the minimum fixed price at which a project’s electricity must be sold in order to recover the total cost of the project, including construction cost, operation and maintenance expense, taxes and the target return on invested capital, over the lifetime of the project. 
  6. The full requirements price of electricity is the price sufficient to pay for the resources required to supply 100% of the electricity demand prevailing during each hour of the year. It includes the cost of energy, capacity and ancillary services. It does not include the charges for transmission and distribution by the electric utilities. 
  7. It is interesting to note that a reduction of 26 million metric tons in California’s CO2 emissions could also be achieved by replacing 5.6 million vehicles, or 20% of California’s fleet of light and heavy duty vehicles, with electric vehicles (EVs). That the electrification of 20% of California’s vehicle fleet could have an impact on CO2 emissions equal to that an increase in the supply of renewable energy from ~40% today to 80% reflects the relatively low carbon intensity of California’s fossil fuel generating fleet, which is predominantly natural gas fired, as compared to its vehicle fleet, whose fuels, gasoline and diesel, are much more carbon intensive. 
  8. For a detailed analysis on this problem, based on actual 2017 hourly data, please see our research report of April 1st,Exploding Duck Curve: What Does It Cost to Achieve 100% Renewable Electricity and What Are the Implications?
  9. To illustrate the huge cost of high levels of renewable penetration, the 11.4 million metric tons of CO2 avoided by raising California’s renewable penetration from 90% to 100% would increase the state’s electricity bill by some $26 billion per year. The state of California could save $8 billion a year, while achieving a similar reduction in CO2, by leasing 4.3 million Nissan Leafs and giving them away for free to new car buyers in lieu of internal combustion vehicles. 
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