The Next Wave of Rate Base Growth – Half of U.S. Generating Capacity Will Retire by 2040: Who Wins and Who Loses?

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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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April 19, 2018

The Next Wave of Rate Base Growth

Half of U.S. Generating Capacity Will Retire by 2040: Who Wins and Who Loses?

The stagnation of U.S. power demand represents a persistent headwind to the growth of vertically integrated regulated utilities. In the coming decade, however, we see in generation capacity retirements the potential to drive a marked acceleration in generation capex and rate base growth. We identify which utilities should benefit most.

Portfolio Manager’s Summary

  • U.S. power demand is stagnant: electricity generation in 2017 remained below its level of a decade earlier, despite a 15% increase in real GDP (Exhibit 2). Indeed, growth in power generation seems to have decoupled from growth in GDP: in 2017, the ratio of the 10-year CAGR in power generation to that of GDP turned negative for the first time (Exhibit 3). Even when measured on a trailing 5-year basis, to avoid the dip in power demand during the 2008-09 recession, generation growth has been negative for 3 years in a row (Exhibit 4). (See our research report of February 14, Power Demand Growth: What Does International Power Demand Growth Tells Us About the Outlook for the U.S. Power Sector?.)
  • Utilities’ generation capex is limited by the stagnation of demand, and is further constrained by the prevailing over-supply of generation capacity in most regional power markets. RTOs in those regions of the country where electricity is largely supplied by vertically integrated, regulated utilities (such SERC and FRCC in the Southeast, SPP and MISO in the Midwest and WECC in the West), had reserve margins ranging from 19% to 27% in 2017 – well above target reserve margins of just 12% to 16% (Exhibit 5). (See our research report of June 7, Creative Destruction and Your IPP Portfolio: Flat Demand & Capacity Additions Likely to Erode Gas & Coal Capacity Factors Through 2019.)
  • Even if power demand continues to stagnate, however, vertically integrated utilities may be only five years away from a period of sustained growth in generation capex, driven by a wave of power plant retirements that we expect to commence in 2024 and to peak approximately ten years later (Exhibit 6).
  • Given the expected useful lives of currently operating generating units, we anticipate that capacity retirements will rise from ~15,000 MW in 2018 to ~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.
  • Reflecting the need to replace aging nuclear and coal fired power plants brought into service in 1970s and, more importantly, the pending retirement of the ~250 GW of gas fired generation capacity added over the years 1998-2005, a fifth of the generation capacity operating in the U.S. today could be retired by 2030, over a third by 2035, and over half by 2040 (Exhibit 8).
  • We expect the investment required to replace retiring capacity to be reflected in rapidly rising capex budgets at the vertically integrated utilities over time, with a corresponding impact on rate base growth.
    • Measured relative to the average annual capital expenditures of the regulated electric utility industry as a whole over 2017-2021, we expect the cost to replace retiring capacity to surge from 2.5% of 2017-2021 average capex in 2018 to ~15% by 2031 and to remain above this level through 2040, peaking at 21.3% of current average annual capex in 2034 (Exhibit 11).
    • Expressed as a percentage of estimated 2017 aggregate electric plant rate base, we see the annual investment required to replace retiring generating capacity quintupling from under 0.4% of 2017 rate base in 2018 to 2.1% by 2031 and remaining above this level through 2040 (Exhibit 11).
  • Because the regulated utilities have generally disclosed their capex plans through 2021, data on capacity retirements are useful primarily in estimating the direction of generation capex over the long term.
    • Over 2021-2030, the utilities facing the largest investment requirement to replace retiring generation capacity are AEE, DTE, OGE, GXP, ETR and D, for each of which our estimate of replacement capex over the decade exceeds 15% of 2021 rate base (Exhibit 12).
    • Over 2031-2040, the utilities facing the largest investment requirement to replace retiring generation capacity are OGE, ETR, SO, DUK, NEE, AEE and DTE, for each of which our estimate of replacement capex over the decade exceeds 30% of 2021 rate base (Exhibit 13).
  • Exhibits 14 and 15 allow us to assess the relative impact over time of capacity retirements on the capital expenditures and rate base growth prospects of the various vertically integrated utilities.
    • Over 2021-2030, the utilities that consistently rank in the top quintiles on the basis of their replacement capex, measured as a percentage of 2021 rate base, are D, AEE, DTE, ETR and WEC.
    • Ranking in the bottom quintiles over this period are IDA, PNW, POR, PNM and ALE.
    • Over 2031-2040, the utilities that rank in the top quintiles on the basis of their replacement capex, measured as a percentage of 2021 rate base, are ETR, OGE, DUK, NEE and DTE.
    • Ranking in the bottom quintiles over this period are NWE, PNM, POR, IDA, HE and ALE.
    • Utilities whose rising opportunities to invest in the replacement generation assets causes their quintile ranking to improve over the long term include ETR (which is expected to transition from the fifth quintile in 2019 to the second quintile during the years 2021-2024 and to the first quintile beginning in 2025), as well as DUK, SO and NEE.
    • Utilities whose opportunities for replacement capex are declining over time, relative to the group, include GXP, HE and WR.
  • Among the vertically integrated utilities, we believe the medium term outlook for replacement capex to be consistent with our inclusion of ALE and POR among our least favored regulated utility stocks, and with our recent upgrade of ETR to among our preferred hybrid utilities (Exhibit 1).
  • In Exhibits 17 and 18 we quantify the expected retirements of existing generating units owned by independent power producers and hybrid utilities. Unlike regulated utilities, we do not expect competitive generators to replace these retiring assets, resulting in declining capacity, revenues and earnings.
    • We expect NRG Energy to face the largest capacity retirements, with ~11% of its existing competitive generation fleet likely to retire over the next five years and ~20% over the next ten years.
    • Over a ten year time frame, capacity retirements will also loom large for VST (~13% of its existing fleet), DYN (~9%), EXC (~7%) and PEG (~5%).
  • The retirements of unregulated, merchant generation may differ materially from our forecast, as they will likely be driven more by power market economics than by age. Changes in the relative prices of natural gas and coal could accelerate or decelerate retirements, as could state policies to promote the growth of renewable generation or support nuclear power plants. Finally, capacity market revenues in PJM, New York and New England could sustain the operation of aging power plants as peakers well beyond their expected retirement dates.
  • Given the large potential impact of capacity retirements on the generating fleets, revenues and gross margins of the competitive generators, we remain cautious on the outlook for these stocks.
    • Best positioned to weather the next decade may be hybrid utilities such as EXC; not only is its nuclear generating fleet is already benefitting from subsidies for clean generation, but its long lived assets and geographically diversified portfolio should allow it to participate in any recovery of energy and capacity prices resulting from the wave of retirements commencing in the mid-2020s.

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

Source: SSR analysis

Details

The Stagnation of U.S. Power Output Will Challenge the Growth of Vertically Integrated Utilities

U.S. power demand is stagnant: electricity generation in 2017 remained below its level of a decade earlier, despite a 15% increase in real GDP (Exhibit 2). Indeed, growth in power generation seems to have decoupled from growth in GDP: the ratio of the 10-year CAGRs in electricity generation to the 10-year CAGR in GDP averaged 0.6 in the years leading up the Great Recession but has fallen dramatically since, hovering near zero in 2015 and 2016 before turning negative for the first time in 2017 (Exhibit 3). Measured on a trailing 5-year basis, to avoid the decline in power demand during the 2008-09 recession, the growth in U.S. power demand generation has been negative for 3 years in a row (Exhibit 4).

Exhibit 2: U.S. Power Generation vs. Real GDP (1990 = 100)

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Source: U.S. Energy Information Administration, Bureau of Economic Analysis, SSR analysis

Exhibit 3: Growth in U.S. Power Generation Exhibit 4: Five-Year CAGR in U.S. Power

vs. Growth in GDP (Ratio of 10-Year CAGRs) Generation, 1997-2017

 

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Source: U.S. Energy Information Administration, Bureau of Economic Analysis, SSR analysis

We have commented elsewhere on how the stagnation of U.S. power demand has challenged the growth of vertically integrated power utilities, whose generating assets often comprise between 30% and 60% of total electric plant rate base. In an environment where electric generation has ceased to grow, investment in the expansion of these generating fleets is no longer necessary. (See our research report of February 14th, 2018, Power Demand Growth: What Does International Power Demand Growth Tells Us About the Outlook for the U.S. Power Sector?.)

The difficulty faced by the vertically integrated utilities is compounded by the prevailing over-supply of generation capacity in most regional power markets of the United States. The regional transmission organizations that serve parts of the country where electricity is supplied, for the most part, by vertically integrated, regulated utilities (such SERC and FRCC in the Southeast, SPP and MISO in the Midwest and WECC in the West), in 2017 had reserve margins ranging from 19% to 27%. The target reserve margins of these RTOs, by contrast, ranged from 12% to 16% (Exhibit 5). (See our research report of June 7, Creative Destruction and Your IPP Portfolio: Flat Demand & Capacity Additions Likely to Erode Gas & Coal Capacity Factors Through 2019.

Exhibit 5: 2017 Reserve Margins by Region

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Source: North American Electric Reliability Corporation

The Looming Wave of Capacity Retirements Could Reignite Investment in Generation Assets

Given the stagnation of U.S. electricity generation over the last decade (Exhibit 2), and more importantly the apparent decoupling of economic growth from power supply, we expect the coming decade to be characterized by little if any growth in total U.S. generation capacity. Even if power demand continues to stagnate, however, we believe the vertically integrated utilities as a group to be approximately five years away from a period of sustained investment in generation assets, driven by an accelerating pace of power plant retirements that we expect to commence in 2024 and to peak approximately ten years later (Exhibit 6).

Exhibit 6 aggregates our estimates of the likely retirement dates 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. 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 6,000 generating units in operation in the United States. Based on the primary fuel and prime mover of these units, we have estimated their likely retirement dates, assuming 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.

What these data suggest is that retirements of U.S. generating capacity will 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.

Exhibit 6: Expected Retirements of U.S. Generating Capacity (MW)

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

We illustrate the scale of this pending wave of retirements in Exhibits 7 and 8. The columns in Exhibit 7 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 8 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 7: Generating Capacity Retirements Exhibit 8: 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

We would caution that investment in replacement capacity will not be the only driver of generation capex by vertically integrated utilities, although by the 2030s it may be the largest. In particular, generation capex is likely to continue to benefit in the medium term from the renewable portfolio standards adopted by 29 states that together account for some 65% of U.S. power demand; these standards stipulate a minimum proportion of utilities retail electricity sales that must be procured from renewable energy resources. Environmental regulations, including those governing cooling water intake by steam turbine generators and the disposal of coal ash residuals and power plant effluents, will continue to drive investment in environmental upgrades of existing power plants. Finally, new environmental regulations, including any state or federal regulations to address emissions of greenhouse gases, may accelerate the retirement of existing fossil fuel generating units.

Who Wins and Who Loses Among the Regulated Utilities?

The expected retirement by 2040 of half of U.S. generation capacity creates, in aggregate, a massive opportunity for investment and rate base growth among the nation’s vertically integrated, regulated utilities. Within this group, which utilities are most likely to benefit from the coming surge in capacity retirements?

To answer this question, we have sorted the retiring generating units by owner, by regulatory status, and expected date of retirement. On this basis, we have quantified for each of the publicly traded electric utilities the MW of capacity expected to be retired from its regulated generating fleet in each of the coming years. To estimate the cost to replace this retiring capacity, we first broke down the retiring units into those whose capacity factor over the last three years has averaged less than 20%, which we deemed to represent peaking capacity, and those whose average capacity factor was 20% or higher (Exhibit 9). On the expectation that regulators will require utilities to replace retiring capacity with the generation technologies that offer the lowest levelized cost of electricity, we have assumed that the retired peaking capacity will be replaced with gas-fired combustion turbines and that non-peaking capacity will be replaced with combined cycle gas turbine generators.[2] We have assumed the installed cost of these new plants to be $950/kW for combustion turbines and $1,200/kW for combined cycle gas turbine generators, reflecting the estimates of the cost of new entry prepared by the Brattle Group for PJM Interconnection for the 2018/2019 planning year.[3] On this basis, we estimated the cost to replace expected retirements of regulated generation capacity for each year through 2040. Exhibit 10 presents this estimate in constant 2018 dollars. As can be seen there, our estimate of the cost to replace retiring capacity rises from less than $2.0 billion in 2018 to more than $10.0 billion annually for each year from 2031 through 2040, reaching a peak of over $15.0 billion in 2034.

Exhibit 9: Expected Retirements of Exhibit 10: Estimated Replacement Cost of Regulated Generation Capacity (MW) Retired Capacity (Billions of Constant 2018 $)

 

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

The actual level of replacement capex by vertically integrated utilities could of course vary markedly from these projections. In particular, the cost new combustion turbines and combined cycle gas turbine generators may rise significantly in nominal terms due to the impact of inflation over the long time horizon of these forecasts. Conversely, the declining real cost of renewable generation and grid scale energy storage could over time offer lower cost alternatives to these conventional generation resources. (See our research report of February 5, Can Grid Scale Energy Storage Compete with Gas Fired Peakers? Not Yet, But Coming Soon.) It is common in many regulatory jurisdictions, moreover, to require utilities to procure renewable resources on a competitive basis, including through long term power purchase agreements with independent generators – limiting the potential for rate base growth.

We expect the investment required to replace retiring capacity to be reflected in materially larger capital expenditure budgets by the regulated electric utilities over time, with a corresponding impact on rate base growth. In Exhibit 11 we express the estimated replacement cost of retiring generation capacity as (i) a percentage of the average annual planned capex of the regulated electric utility industry over 2017-2021 (left hand chart) and (ii) as a percentage of our estimate of the 2017 aggregate electric plant rate base of the regulated utility industry (right hand chart). As can be seen on the left, we expect the cost to replace retiring capacity, expressed in constant 2018 dollars, to be equivalent in 2018 to only 2.5% of the average annual total capex of the regulated electric utility industry over 2017-2021, but to rise six-fold to ~15% by 2031 and to remain above this level through 2040, peaking at 21.3% of current average annual capex in 2034. Expressed as a percentage of estimated 2017 aggregate electric plant rate base, we see the cost to replace retiring generating capacity rising from less than 0.4% of 2017 rate base in 2018 to 2.1% by 2031 and remaining above this level through the end of the decade.

Exhibit 11: Aggregate Estimated Cost to U.S. Regulated Electric Utilities of Replacing Retired Generation Capacity, 2018-2040

As % of Average Annual Planned Capex, 2017-2021 As % of Estimated 2017 Electric Plant Rate Base

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

Because the regulated utilities have generally disclosed their capex plans through 2021, data on capacity retirements are useful primarily in estimating the direction of generation capex over the long term. To assess the impact of rising capacity retirements on individual utility stocks, we have estimated the cost to replace this capacity by utility for each year through 2040. Exhibit 12 presents our estimates of the cost to replace retiring generation capacity over 2021-2030, expressed as a percentage of each utility’s 2021 estimated rate base, while Exhibit 13 presents our estimates of replacement cost over 2031-2040. Please note that both exhibits exclude regulated transmission and distribution utilities whose generation assets have been divested (e.g., ED and ES) or deregulated (e.g., EXC and PEG). They also exclude regulated utilities that retain legacy regulated generating units but which operate in states that have deregulated power generation (e.g., PCG’s investment in its Diablo Canyon nuclear power plant); we believe these units are unlikely to be replaced with non-utility generating assets upon retirement, and therefore not to represent an opportunity for regulated replacement capex.

As can be seen in Exhibit 12, over 2021-2030, the utilities facing the largest investment requirement to replace retiring generation capacity are AEE, DTE, OGE, GXP, ETR and D, for each of which our estimate of replacement capex over the decade exceeds 15% of 2021 rate base. Over 2031-2040, the utilities facing the largest investment requirement to replace retiring generation capacity are OGE, ETR, SO, DUK, NEE, AEE and DTE, for each of which our estimate of replacement capex over the decade exceeds 30% of 2021 rate base (Exhibit 13).

Exhibit 12: Estimated Cost to Replace Generation Capacity Retired Over 2021-2030 as % of 2021 Estimated Electric Plant Rate Base

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

Exhibit 13: Estimated Cost to Replace Generation Capacity Retired Over 2031-2040 as % of 2021 Estimated Electric Plant Rate Base

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

Exhibits 14 and 15 allow us to assess the relative impact over time of capacity retirements on the capital expenditures and rate base growth prospects of the various vertically integrated utilities. Please note that the utilities whose regulated rate base does not include generation plant (e.g., AGR, ED, EE, EIX, ES, EXC, PCG and PEG) are excluded from these charts.

Over 2021-2030, the utilities that consistently rank in the top quintiles on the basis of their expected replacement capex, measured as a percentage of estimated 2021 rate base, are D, AEE, DTE, ETR and WEC (Exhibit 14). Ranking in the bottom quintiles over this period are IDA, PNW, POR, PNM and ALE.

Over 2031-2040, the utilities that rank in the top quintiles on the basis of their expected replacement capex, measured as a percentage of estimated 2021 rate base, are ETR, OGE, DUK, NEE and DTE (Exhibit 14). Ranking in the bottom quintiles over this period are NWE, PNM, POR, IDA, HE and ALE.

Utilities whose rising opportunities to invest in the replacement generation assets causes their quintile ranking to improve over the long term include ETR (which is expected to transition from the fifth quintile in 2019 to the second quintile during the years 2021-2024 and to the first quintile beginning in 2025), as well as DUK, SO and NEE. Utilities whose opportunities for replacement capex are declining over time, relative to the group, include GXP, HE and WR.

Exhibit 14: Estimated Cost to Replace Generation Capacity Retired as % of 2017 Rate Base – Quintile Ranking (Vertically Integrated Utilities Only) (1)

__________________________________________________________________________________________ 1. For the data underlying this quintile ranking, please see Exhibit 21 in the appendix to this report. Source: Energy Information Administration, S&P Global, SSR research and analysis

Exhibit 15: Estimated Cost to Replace Generation Capacity Retired as % of 2017-2021 Average Annual Capex – Quintile Ranking (Vertically Integrated Utilities Only) (1)

__________________________________________________________________________________________ 1. For the data underlying this quintile ranking, please see Exhibit 22 in the appendix to this report. Source: Energy Information Administration, S&P Global, SSR research and analysis

We believe the medium term outlook for replacement capex to be consistent with our inclusion of ALE and POR among our least favored regulated utility stocks, and with our recent upgrade of ETR to among our preferred hybrid utilities (Exhibit 1). (See our note of April 3, 2018, Utility Portfolio Update: Adding ETR to Our List of Preferred Utilities; FE, EIX and PCG Remain Our Favorite Names in the Sector, While SO Remains a Concern.)

The Impact on Competitive Generators

In our report of September 7, 2017, Publicly Traded Competitive Generators: Crawling Towards Extinction, we compared the all-in cost of power from a new combined cycle gas turbine plant to the gross margin likely to be earned by the unit given currently prevailing forward prices for energy and capacity in various regions of the country (Exhibit 16). We concluded that, in the various competitive power markets around the country, investment in new CCGT capacity is uneconomic.

Exhibit 16: Expected Generation Gross Margin of a New CCGT by Region Compared to the Generation Gross Margin Required for Full Cost Recovery (1)

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1. For purposes of our analysis, we have averaged the next ten years’ forward spark spreads and the next three years’ capacity prices. Forward spark spreads reflect currently prevailing forward price curves for electricity and the estimated cost of the natural gas required to generate it at a CCGT with an assumed heat rate of 6.5 MMBtu/MWh.

Source: Bloomberg, SNL, Energy Information Administration, Lazard’s Levelized Cost of Energy Analysis – Version 10.0, SSR analysis.

If so, the generation capacity retired in competitive power markets in the coming years is unlikely to be replaced. Absent a marked change in energy and capacity prices, therefore, the expected retirement of generation capacity in these markets will be reflected in a contraction of the competitive generating fleets of the independent power producers and hybrid utilities that own the retiring units. Over time, of course, these retirements will contribute to a tightening of power markets and rising energy and capacity prices, enhancing the gross margins of the power plants that remain and, eventually, incentivize the construction of new generation.

We have estimated the retirement dates of the competitive generating units in the United States using the same methodology as we applied to the fleets of the vertically integrated regulated utilities. In Exhibits 17 and 18 we allocated these expected retirements to the independent power producers and hybrid utilities that own the retiring units. As these exhibits illustrate, NRG Energy is likely to face the largest capacity retirements, with ~11% of its existing competitive generation fleet expected to retire over the next five years and ~20% over the next ten years. Over a ten year time frame, capacity retirements will also loom large for VST (~13% of its existing fleet), DYN (~9%), EXC (~7%) and PEG (~5%).

Exhibit 17: Capacity Retirements 2018-2022 as % of Total 2016 Capacity    Exhibit 18: Capacity Retirements 2018-2027 as % of Total 2016 Capacity

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

As a result of these and other scheduled retirements, we expect to see over the next five years the withdrawal of a significant proportion of the capacity currently available to the California ISO, New York ISO and ERCOT, where we estimate that ~12%, 10% and 9%, respectively, of existing capacity is likely to be retired by 2022 (Exhibit 19). Looking out over the next ten years, we expect capacity retirements totaling between 14% and 16% of the currently operating capacity in most of the power markets around the country. The exception is likely to be the New York ISO, where the planned retirement, among others, of Entergy’s 2000 MW Indian Point nuclear power plant will contribute to an expected contraction of existing generation capacity of over 25% (Exhibit 20).

Exhibit 19: Capacity Retirements by ISO, Exhibit 20: Capacity Retirements by ISO,

2018-2022 (% of Total 2016 Capacity) 2018-2027 (% of Total 2016 Capacity) 

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

Given the large potential impact of capacity retirements on the generating fleets, revenues and gross margins of the competitive generators, we remain cautious on the outlook for these stocks. Best positioned to weather the next decade may be hybrid utilities such as EXC; not only is its nuclear generating fleet is already benefitting from subsidies for clean generation, but its long lived assets and geographically diversified portfolio should allow it to participate in any recovery of energy and capacity prices resulting from the wave of retirements commencing in the mid-2020s.

We note that the retirements of unregulated, merchant generation may differ materially from our forecast, as they will likely be driven more by power market economics than by age. Changes in the relative prices of natural gas and coal could accelerate or decelerate retirements, as could state policies to promote the growth of renewable generation or support nuclear power plants. Finally, capacity market revenues in PJM, New York and New England could sustain the operation of aging power plants as peakers well beyond their expected retirement dates.

Appendix 1: Regulated Utilities’ Estimated Cost to Replace Generation Capacity

Exhibit 21: Estimated Cost to Replace Generation Capacity Retired as % of 2017 Rate Base (Vertically Integrated Utilities Only)