Half of U.S. Generating Capacity Will Retire by 2040: What Is the Impact on Power Supply, Power Markets, Coal Burn and Rail Volumes?

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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 21, 2018

Half of U.S. Generating Capacity Will Retire by 2040:

What Is the Impact on Power Supply, Power Markets, Coal Burn and Rail Volumes?

In our research report of April 19th, The Next Wave of Rate Base Growth – Half of U.S. Generating Capacity Will Retire by 2040: Who Wins and Who Loses?, we estimated the scale of retirements of U.S. power generation capacity through 2040. In this note, we estimate how the composition of U.S. power supplies will change as a result, assess the implications for power sector consumption of coal and gas, and identify those power markets where capacity retirements will have the greatest impact.

  • We have forecast the size and output of the nation’s coal, nuclear, gas and renewable generating fleets based on a series of assumptions: that plants in operation today are retired at the end of their normal useful lives, that renewable generation capacity continues to expand at the pace seen in recent years, and that gas fired generation capacity is added to replace the capacity lost to retirements and required by the growth in power demand, which we estimate at 0.4% p.a.
  • Our analysis suggests that over a fifth of the generation capacity in operation in the United States today could be retired by 2030, over a third by 2035 and over half by 2040.
  • Coal fired and nuclear capacity and generation are forecast to enter a steady decline as plants are assumed to be retired at the end of their estimated useful lives (60 years for both technologies) and their capacity and output replaced by a combination of gas fired and renewable generation (Exhibits 7 and8).
  • The decline in U.S. coal and nuclear generating capacity will drive a similar drop in coal and nuclear generation (see Exhibits 7 and 9). We estimate that:
    • Coal fired generation will fall by ~13% by 2025, by ~26% by 2030, by ~43% by 2035 and by ~62% by 2040; and
    • Nuclear generation will decrease by ~7% by 2025, ~10% by 2030, ~32% by 2035 and ~45% by 2040.
  • This results in a dramatic shift in the generation mix by 2040, with coal and nuclear each declining to 10% of output and natural gas and renewables (including hydro) each rising to 40% of output (see Exhibit 11). In particular:
    • Coal declines from its current 30% to ~20% by 2030 and ~10% by 2040;
    • Nuclear generation falls from 20% currently to ~17% by 2030 and ~10% by 2040;
    • Natural gas falls from 34% today to 32% by 2030 before rising to 40% by 2040;
    • The combined output of all forms of renewable power plants, including hydroelectric, rises from 16% of total generation today to ~30% by 2030 and ~40% by 2040.
  • We expect deliveries of thermal coal and nuclear fuel to U.S. power plants to fall in parallel with the decline in generation. As can be seen in Exhibit 12, we expect coal deliveries to fall by almost 30% by 2025, by over 40% by 2030, by over 50% by 2035 and by over 60% by 2040.
  • We expect the Southeast and industrial Midwest to experience the largest declines in coal fired generation, eroding coal transportation volumes for railroads serving those regions (Exhibits 13 and 14).
    • By 2030, we expect to see ~30% cumulative declines in coal fired generation occurring in the Southeast Electric Reliability Council (SERC) and the ReliabilityFirst region in the Midwest and MidAtlanic, with cumulative declines of ~60% in these regions by 2035 and ~80% by 2040.
    • In the Western Electric Coordinating Council (WECC), we expect the decline in coal fired generation to exceed 30% by 2030, and to approach 50% by 2035 and 70% by 2040.
  • Natural gas burned in power plants is expected to be broadly flat through 2030, and rise by 10% by 2040.
    • We expect gas fired generation capacity to expand by 16% through 2030, as capacity is added to offset coal and nuclear retirements and keep pace with the growth of peak demand.
    • However, gas fired generation and thus gas deliveries to power plants is forecast to rise by only 3% through 2030, as rapid increases in renewable generation suppress the output of the gas fleet.
    • From 2030 through 2040, when coal and nuclear retirements are expected to peak, we anticipate both gas fired capacity and generation will rise markedly; by 2040, we expect gas fired capacity to exceed the 2016 level by 40% and gas fired generation to have increased by 36%.
    • However, because of the fuel efficiency of the new combined cycle gas turbines is much higher than that of the plants operating today, the estimated increase in power sector consumption of natural gas by 2040 (10%) will materially lag the estimated increase in gas fired generation (36%).
  • Retirements of firm generation capacity on the scale we are forecasting will materially erode reserve margins in the principal competitive wholesale power markets, putting significant upward pressure on capacity prices over time (see Exhibits 17 and 18).
    • Through 2025, we expect the largest percentage declines in existing generation capacity in the New York ISO (~20%) and the California ISO (~15%), reflecting in part the planned retirements of the Indian Point and Diablo Canyon nuclear power plants.
    • The New York ISO should continue to lead the nation in retirements through 2035. By 2030, we expect almost 35% of operating capacity on the NYSIO to have retired, and 45% by 2035.
    • After the NYISO, we expect the largest capacity losses New England and PJM, with over 20% of the existing fleet expected to be retired by 2030 and almost 40% by 2035.
      • MISO will experience similarly large retirements, but, with primarily regulated generation, there should be little upward pressure on capacity prices except in Illinois.
    • In the long term, we expect CAISO to be least affected by retirements, losing ~30% of its existing capacity by 2040 as against a range of ~45% to 60% in the other markets.
    • Due to the absence of a capacity market, large retirements in ERCOT will likely result in significant increases in scarcity pricing and price volatility for energy.
  • Our forecast of declining coal fired generation and broadly flat gas fired generation is consistent with a decrease of over 20% in power sector emissions of CO2 by 2030, a decrease of over 30% by 2035 and a decrease of over 40% by 2040.
    • Moreover, as fuel use in power generation transitions from coal (which emits ~1.0 metric ton of CO2 per MWh) to gas (which emits ~0.4 metric tons) and renewables (which emit none), the rate of CO2 emissions per MWh generated by the U.S. power industry is expected to fall from ~0.5 metric tons currently to ~0.3 metric tons by 2040.

Exhibit 1: Heat Map: Preferences Among Utilities, IPP and Clean Technology

Source: SSR analysis

Details

Background

In our research report of April 19th, The Next Wave of Rate Base Growth – Half of U.S. Generating Capacity Will Retire by 2040: Who Wins and Who Loses?, we estimated the likely retirement date each of the generating units currently in operation in the United States, based upon the year they entered service and our estimate of the likely useful life of these plants given their generation technology.

In Exhibit 2, we present the results of our analysis. As can be seen there, we expect retirements of U.S. generating capacity to rise almost without interruption from 2021 through 2037, reflecting the need to replace aging nuclear and coal fired steam turbine generators brought into service in the 1970s and, more importantly, the likely retirement commencing in the early 2030s of the ~250 GW of gas fired generation capacity added over the years 1998-2005. We anticipate that capacity retirements will reach ~20,000 MW annually in the late 2020s, ~30,000 MW annually by the early 2030s and ~40,000 MW annually by the middle years of that decade.

We illustrate the scale of this pending wave of retirements in Exhibits 3 and 4. The columns in Exhibit 3 present the percentage of U.S. generation capacity that we expect to be retired in five year intervals through 2040. As can be seen there, the share of U.S. generation capacity expected to be retired rises from ~7.4% over the five years 2021-2025 to 13.6% over 2031-2035 and 16.1% over 2035-2040, implying the loss of 30% of U.S. generation capacity in the decade of the 2030s. Exhibit 3 presents the cumulative impact of this pace of retirements, illustrating how over a fifth of the generation capacity in operation in the United States today could be retired by 2030, over a third by 2035 and over half by 2040.

Exhibit 2: Expected Retirements of U.S. Generating Capacity (MW)

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Source: Energy Information Administration, S&P Global, SSR research and analysis

Exhibit 3: Generating Capacity Retirements Exhibit 4: Cumulative Generating Capacity

by Period (% of Total 2016 Capacity) Retirements (% of Total 2016 Capacity)

 

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Source: Energy Information Administration, S&P Global, SSR research and analysis

In this research report, we estimate the capacity additions required to offset these retirements and to keep pace with the growth in U.S. power demand through 2040. We have estimated the likely composition of these new capacity additions by technology, and trace the resulting change in the composition of the U.S. generating fleet. We have assessed how the changing technological profile of the U.S. generating fleet will be reflected in the sources of energy used to generate electricity in the United States, the consequent changes in power sector demand for coal and natural gas, and the impact of these changes on power sector emissions of CO2. We have identified a long term trend –the continuous rise in zero variable cost renewable generation – that will likely erode the capacity factor of the gas fired generating fleet over time, rendering it increasingly vulnerable to competition from energy storage. Finally, we have identified those regions and wholesale power markets will be most affected by the coming wave of retirements.

Assumptions

To forecast the changing composition of the U.S. power generating fleet over time, we have estimated the retirements dates of those generating units currently in operation, estimated the annual increase in generation capacity required to meet the growth in peak demand, and estimated the likely mix of generation technologies required to offset these retirements and growth in load. We explain the assumptions underpinning each of these estimates in the paragraphs below.

The Energy Information Administration of the Department of Energy maintains data on the capacity, primary fuel, prime mover, and commercial operation date of the approximately ~16,000 generating units in operation in the United States. Based on the primary fuel and prime mover of these currently operating generating units, we have estimated their likely retirement dates. We have assumed average useful lives of 60 years for nuclear, coal, gas and oil fired steam turbine generators and 35 years for gas and oil fired combustion turbines and combined cycle gas turbine generators.[1] Where the owners of a unit have announced its planned retirement date, and this date has been accepted by regional reliability coordinators, we have incorporated this data into our model.

We have estimated the growth in peak power demand, and the capacity additions required to supply it, as a function of the growth in electricity consumption. To estimate the growth of electricity consumption, we first calculated the historical relationship between the growth of electricity consumption and the growth of real GDP. Exhibit 5 presents the historical ratio of (i) the 10-year CAGR in U.S. electricity consumption to (ii) the 10-year CAGR in real U.S. GDP. Capitalizing on the OECD’s long term forecasts of GDP growth, we have used the historical ratio of electricity consumption to GDP over the last ten years to estimate the likely growth of U.S. electricity consumption to 2040 (Exhibit 6).

Exhibit 5: Ratio of 10 Year CAGR in U.S. Exhibit 6: Forecast Growth in U.S.

Generation to 10 Year CAGR in U.S. GDP GDP and Power Demand

 

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Source: Organization for Economic Co-operation and Development, Energy Information Administration, SSR analysis and estimates

To estimate the firm generation capacity required to meet the growth in peak demand, we have assumed that load shapes and loss ratios are unchanging over time, so that the system requirement for firm generation capacity grows at the same rate as electricity consumption. More specifically, we have assumed (i) that peak power demand grows at the same rate as overall electricity consumption, and (ii) that the current excess of generation over electricity consumption – primarily attributable to power losses on the transmission and distribution grid – will persist in future, and that the capacity of the generation fleet must remain sufficient to offset these losses.[2] Given these assumptions, our forecast rate of growth in firm generation capacity is identical to that of electricity consumption.

To estimate the required growth in fossil generation capacity, we have adjusted our estimate of the required growth in firm generation capacity to account for the firm capacity value of expected additions of renewable generation capacity. Based on the recent pace of renewable capacity additions in the United States, we have forecast annual additions of renewable generation capacity at 10.5 GW of new solar, 6.0 GW of new wind and 0.5 MW of other renewable capacity. While the output of individual solar and wind power plants is impossible to predict, the output of large, geographically diverse fleets of wind and solar power plants rarely falls below a certain minimum percentage of their nameplate capacity; this minimum percentage of nameplate capacity can also be treated as firm capacity to meet demand during the highest demand hours of the year. Based on the performance of recent renewable generation projects, we have attributed a firm capacity value of 10% to wind, 40% to solar and 85% to other renewable resources, such as biomass and geothermal. The remaining need for firm generation capacity we have assumed is met by through the construction of gas fired power plants, reflecting the far lower levelized cost of energy of this technology as compared to coal or nuclear. Lazard’s Levelized Cost of Energy Analysis – Version 11.0, which was published in November of 2017, identifies the combined cycle gas turbine as the lowest cost source of base load and load following capacity, with an estimated the levelized cost of electricity at ~$42 per MWh, as against ~$60 per MWh for a conventional coal fired steam turbine generator and $112-$183/MWh for a new nuclear power plant. Similarly, the report identifies two gas fired generation technologies – gas fired reciprocating engines and gas turbine generators – as the lowest cost sources of peaking capacity.

Conclusions

We set out below the results of a forecast based on the assumptions set out above: ~0.4% annual load growth, the gradual but accelerating retirement of existing coal and nuclear generating capacity, continued rapid growth in renewable generation capacity, and a reliance on gas fired generation technologies to ensure that sufficient firm generation capacity is available to meet the growth in power demand.

Exhibits 7 and 8 set out the resulting trajectory of generation capacity and power output by fuel. As can be seen there, coal fired and nuclear capacity and generation are forecast to enter a steady decline as plants are assumed to be retired at the end of their estimated useful lives (60 years for both technologies) and their capacity and output replaced by a combination of gas fired and renewable generation. The decline in U.S. coal and nuclear capacity will drive a similar drop in coal and nuclear generation. As can be seen in Exhibit 9, we estimate that U.S. coal fired generation will have decreased by ~13% by 2025, by ~26% by 2030, by ~43% by 2035 and by ~62% by 2040. Based on the age of the nuclear fleet, we expect U.S. nuclear generation to fall more slowly, by ~7% by 2025, ~10% by 2030, ~32% by 2035 and ~45 by 2040. As these percentages indicate, the bulk of coal and nuclear capacity retirements is expected to occur in the decade of the 2030s.

Exhibit 7: Trajectory of U.S. Generating Capacity and Generation by Fuel (2016 = 100)

Capacity (GW) Generation (GWh)

 

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Source: Energy Information Administration, S&P Global, SSR research and analysis

Exhibit 8: Cumulative % Change in Coal, Nuclear, Gas and Renewable Capacity (GW)

 

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Source: Energy Information Administration, S&P Global, SSR research and analysis

Exhibit 9: Cumulative % Change in Coal, Nuclear, Gas and Renewable Generation (GWh)

 

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Source: Energy Information Administration, S&P Global, SSR research and analysis

By contrast, we expect the nation’s gas fired and renewable generating fleets to continue to grow. Based on the recent pace of renewable capacity additions in the United States, we have forecast annual additions of renewable generation capacity at 10.5 GW of new solar, 6.0 GW of new wind and 0.5 MW of other renewable capacity. We estimate, however, that these capacity additions will contribute only 5 to 6 GW annually to the nation’s firm generation capacity; given the intermittent nature of wind and solar generation, we attribute a firm capacity value of only 10% to wind, 40% to solar and 85% to other renewable resources, such as biomass and geothermal. Given our assumption of only 0.4% annual growth in power demand, however, the contribution of new renewable generation to the firm capacity of the U.S. fleet is sufficient in our forecast to offset the forecast growth in peak demand (U.S. firm generation capacity totals just over 1000 GW so that the annual increase required to offset the 0.4% annual growth in demand is only 4-5 GW per year).

To offset the loss of firm capacity due to the retirement of coal and nuclear power plants, however, we foresee a need for substantial annual additions of conventional generation capacity. We expect these need to be met through additions of gas fired generating capacity: combined cycle gas turbine plants have a far lower levelized cost of energy than new coal or nuclear power plants, and gas turbines and gas fired reciprocating engines similarly constitute the lowest cost alternatives for new peaking capacity.[3] As a result, our forecast has U.S. gas fired generation capacity expanding by ~9% by 2025, ~16% by 2030, ~28% by 2035 and ~40% by 2040 (see Exhibit 8).

This forecast growth in gas fired generation capacity, however, does not drive a similar expansion in gas fired generation (compare the left hand charts in Exhibits 8 and 9). Rather, we expect the bulk of the new generation required to offset the loss of coal and nuclear generation, and keep up with the growth in demand, to be met by the output of the nation’s growing renewable fleet. The United States generates ~4.1 billion MWh of electricity annually; our forecast of ~0.4% annual growth in power demand is thus consistent with a need for an additional 15 to 20 million MWh of generation annually. As noted, we forecast annual additions of 10.5 GW of new solar capacity, 6.0 GW of new wind and 0.5 MW of other renewable capacity; based on the performance of recently constructed renewable power plants, we have assumed average capacity factors 37% for wind, 19% for solar and 93% for other renewables. As a result, U.S. renewable generation is expected to grow by ~45 million MWh annually. The excess of this incremental renewable generation over the estimated growth in demand is thus some ~25 to ~30 million MWh annually. On the assumption that zero variable cost renewable generation will be dispatched before all conventional power sources, we estimate that forecast growth in renewable generation capacity will offset 70%, on average, of the new generation required in the United States through 2030 (see the right hand chart of Exhibit 10).

Exhibit 10: Drivers of the Need for New Generation and Composition of New Generation Drivers of the Need for New Generation Composition of New Generation

 

Based on these assumptions, our forecast is for a marked shift in the composition of U.S. power output over time with a steadily falling share for nuclear and coal, a gradually expanding share for natural gas (particularly in the 2030s, when coal and nuclear capacity retirements hit their peak) and a rapidly rising share of renewable generation (see Exhibit 11). We see the contribution of nuclear generation to the total falling from 20% currently to ~17% by 2030 and ~10% by 2040. The drop in coal fired generation is both larger and more rapid, with coal’s share of total power output expected to fall from 30% current to ~20% by 2030 and ~10% by 2040. In marked contrast, the combined output of all forms of renewable power plants, including hydroelectric, is expect to rise from 16% of total generation today to ~30% by 2030 and ~40% by 2040. The share of wind alone is forecast to rise from 6% today to ~12% by 2030 and ~16% by 2040, while that of solar rises from 1% to ~7% and 11% in 2030 and 2040, respectively (see the bottom chart of Exhibit 11).

Because we assume that zero variable cost renewable generation is dispatched ahead of natural gas, we forecast little growth through 2030 in gas fired generation, despite the forecast increase in the capacity of the gas fired fleet. From 2017 through 2030, we see the output of the nation’s gas fired power plants rising by only 3% in aggregate (see Exhibit 9), and expect the share of gas fired generation to total U.S. power output to decline, from 34% today to ~32%. It is only in the following decade, when coal and nuclear retirements reach their peak, that we see a surge in gas fired generation to offset the loss: by 2035, we expect to see the cumulative increase in gas fired generation since 2017 to reach ~19%, raising its share of the total to ~36%; by 2040, we expect a cumulative increase in gas fired generation of ~36%, raising its share of the total to ~40% (see the bottom chart of Exhibit 11).

The expected decline in U.S. coal fired generation as the existing coal fired power plants are gradually retired will have a commensurate impact on deliveries of thermal coal to the power industry. We present our forecast of thermal coal deliveries to U.S. power plants in Exhibit 12; as can be seen in the right hand chart, we expect coal deliveries to fall by almost 30% by 2025, by over 40% by 2030, by over 50% by 2035 and by over 60% by 2040.

Reflecting the broadly stable outlook for gas fired generation, we foresee little change in the power sector’s consumption of natural gas. This is true even in the decade of the 2030s, when we forecast a significant increase in gas fired generation to offset coal and nuclear retirements and when the bulk of the existing gas fired fleet must also be replaced. Because the fuel efficiency of the new combined cycle gas turbines is much higher than that of the plants they are replacing, we expect the increase in power sector consumption of natural gas by 2040 (10%) to materially lag the estimated increase in gas fired generation (36%) (compare Exhibits 11 and 12).

Exhibit 11: Fuel Breakdown of U.S. Electricity Generation (GWh)

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Source: Energy Information Administration, S&P Global, SSR research and analysis

Exhibit 12: Total Deliveries of Coal and Natural Gas to U.S. Power Plants

Tcf of Gas and Millions of Tons of Coal 2017 = 100

 

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Source: Energy Information Administration, S&P Global, SSR research and analysis

To facilitate analysis of the decline in coal deliveries on rail traffic by region, we break down the coal fired generation lost due to coal plant retirements since 2017 by NERC region in Exhibit 13. Through 2025, some 80% of the expected decline in coal fired generation (and, by extension, coal deliveries) will occur in four regions: the Western Electric Coordinating Council (WECC), 23%; the Texas Reliability Entity (TRE), 13%; the Southeast Electric Reliability Council (SERC), 25%; and the ReliabilityFirst Corporation (RFC), 29%. (A map showing the location of the various FERC regions is presented in Exhibit 15.) From 2030 on, however, just two regions account for ~65% of the decrease in coal fired generation: RFC (~34%) and SERC (~31%).

Exhibit 13: Breakdown of Cumulative Coal Fired Generation Lost Due to Plant Retirements by NERC Region

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Source: Energy Information Administration, S&P Global, SSR research and analysis

In Exhibit 14, we also show the cumulative decline in coal fired generation by region due to coal plant retirements since 2017, but do so using 100 as a base. Plotted this way, it is possible to see that the largest percentage declines in coal fired generation will initially occur in the Northeast Power Coordinating Council (NPCC), Texas Reliability Entity (TRE), Florida Reliability Coordinating Council (FRCC) and the Western Electric Coordinating Council (WECC). By 2030, however, we expect to see ~30% cumulative declines in coal fired generation in ReliabilityFirst Corporation (RFC) and the Southeast Electric Reliability Council (SERC), rising to ~60% in these regions by 2035 and ~80% by 2040.

Exhibit 14: Cumulative Decline in Coal Fired Generation Due to Coal Plant Retirements by NERC Region (2017=100)

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Source: Energy Information Administration, S&P Global, SSR research and analysis

Exhibit 15: Map of NERC Regions in the United States

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Source: North American Electric Reliability Corporation

Our forecast of a continuous decline in coal fired generation through 2040 should be reflected in a commensurate decline in the CO2 emissions of the coal fired generating fleet. By contrast, CO2 emissions from gas fired generation are expected to remain broadly flat through 2030, and then to rise modestly (see the left hand chart of Exhibit 16), implying that the total CO2 emissions of the U.S. power sector will fall less rapidly than those from coal fired generation alone (see the right hand chart of Exhibit 16). Nonetheless, our forecast decline in coal fired generation would be consistent with a decrease of over 20% in power sector emissions of CO2 by 2030, a decrease of over 30% by 2035 and a decrease of over 40% by 2040. Moreover, as fuel use in power generation transitions from coal (which emits ~1.0 metric ton of CO2 per MWh) to gas (which emits ~0.4 metric tons) and renewables (which emit none), the rate of CO2 emissions per MWh generated by the U.S. power industry is expected to decline from ~0.5 metric tons currently to ~0.3 metric tons by 2040.

Exhibit 16: CO2 Emissions from U.S. Power Plants

Millions of Metric Tons 2016 = 100

 

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Source: Energy Information Administration, S&P Global, SSR research and analysis

Impact on Competitive Markets

Retirements of firm generation capacity on the scale we are forecasting will have a material impact on the total capacity available to meet demand across the various regions of the country (see Exhibit 17). In regions with regulated utility generation, the requirement to maintain adequate supply to meet demand should ensure new capacity is built. However, in the competitive wholesale markets, reserve margins could see significant declines (see Exhibit 18). Given the expected rapid growth of renewable generation, both the hours of operation and energy prices received by conventional generators in competitive power markets will be eroded, suppressing energy revenues and requiring materially higher capacity prices as an incentive for new merchant generation to be built. In ERCOT, which lacks a capacity market, energy prices during scarcity hours will come under significant upward pressure and will increase in volatility. We expect to see the greatest upward pressure on capacity prices in markets where the scale of expected retirements is largest.

Exhibit 18 presents our estimates of the percentage of existing capacity that will be retired in the various wholesale power markets through 2040. As can be seen there, the New York ISO and the California ISO are expected to see retirements by 2025 equivalent to ~20% and ~15%, respectively, of their existing capacity, reflecting in part the planned retirements of the Indian Point and Diablo Canyon nuclear power plants. While retirements in the California ISO should be relatively limited thereafter, New York ISO continues to experience the most rapid rate of retirements through 2035 among competitive markets, with almost 35% of the currently operating capacity retiring by 2030, rising to 45% by 2035. After New York, we expect the largest capacity losses in New England and PJM, with over 20% of the existing fleet expected to be retired by 2030 and almost 40% by 2035. While MISO experiences similar levels of retirements, most generation is owned by regulated utilities, so market impacts should be limited, except in Illinois, which is deregulated.

In the long term, we expect CAISO to be least affected by retirements, losing ~22% of its current capacity by 2035 and ~31% by 2040. By contrast, we expect the other ISOs to have lost between 31% and 45% of their existing capacity by 2035 and between 45% and 60% by 2040. In New England and PJM, we expect retirements equivalent to ~38% of existing capacity by 2035. By 2040, we expect retirements equivalent to between 51% to 58% of existing capacity in ERCOT, New England and PJM.

However, while rising capacity or energy prices due to retirements should help generators in competitive markets, it is difficult to forecast who will benefit most. First, in regions with capacity markets, higher capacity prices could reduce capacity retirements by encouraging power plant owners to keep overage plants on line just to meet peaking needs and collect capacity payments, including by switching coal fired plants to gas, as we have see in PJM over the past few years. Second, the owners of existing generation only benefit if they do not retire their generation, but others do, creating a large game theory experiment as generation owners wait to see who blinks first.

Exhibit 17: Percentage of Existing Capacity Remaining After Retirements, by NERC Region

 

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Source: Energy Information Administration, S&P Global, SSR research and analysis

Exhibit 18: Percentage of Existing Capacity Remaining After Retirements, by ISO

 

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Source: Energy Information Administration, S&P Global, SSR research and analysis

©2018, 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. Rather than assume that each steam turbine generator is retired on the 60th anniversary of its in-service date, and each gas turbine generator on its 35thanniversary, we have constructed distributions of potential retirements dates around these expected dates. For example, for all the steam turbine generating units whose 60th year of operation falls in 2030, we have assumed that the actual retirement dates of this cohort of units is distributed over 19 years centered on 2030, i.e., from 2021 through 2039. We assigned the highest probability (10%) to retirement in 2030, the 60th year of operation, and declining probabilities for each year above and below 2030 (i.e., 9% probability of retirement in 2029 or 2031, 8% probability in 2028 or 2032, 7% in 2027 and 2033 and so forth). 
  2. Because of the time required for planning and constructing new gas-fired generation capacity, for the years from 2018 through 2020 we assumed generating capacity grows only by those gas-fired power plants currently under construction. 
  3. Lazard’s Levelized Cost of Energy Analysis – Version 11.0, which was published in November of 2017, identifies the combined cycle gas turbine as the lowest cost source of base load and load following capacity, with an estimated the levelized cost of electricity at ~$42 per MWh, as against ~$60 per MWh for a conventional coal fired steam turbine generator and $112-$183/MWh for a new nuclear power plant. Similarly, the report identifies two gas fired generation technologies – gas fired reciprocating engines and gas turbine generators – as the lowest cost peaking technologies. 
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