GE, SIE, MHVYF: The Impending Recovery in Gas Turbine Orders

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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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June 19, 2018

GE, SIE, MHVYF:

The Impending Recovery in Gas Turbine Orders

In our report of May 10thThe Impending Recovery in the Market for Power Generation Equipment: A Global Perspective, we presented our global forecast of power generation capacity additions. In this report, we have modified and calibrated our previous analysis to focus on the medium-term outlook for global gas turbine orders. We find strong evidence for a recovery, sustained by an accelerating pace of power plant retirements, particularly in North America, Europe and Japan (Exhibits 1, 2 & 6).

  • Our forecast, predicated upon the age of the existing fleet, the historical pattern of power plant retirements, a very conservative estimate of power demand growth, and a continuation of existing patterns of technology choice, is consistent with gas turbine orders rising from 31 GW in 2020 to 49 GW in 2025 and 70 GW in 2030 (Exhibit 2), implying 5-year growth rates of 9.4% p.a. over 2020-25 and 7.6% p.a. over 2025-30.
  • We have modeled four alternative scenarios, and two combinations thereof. Specifically:
    • Scenario B assumes a 50% increase in the annual pace of wind and solar capacity additions;
    • Scenario C assumes that from 2025 on, electric energy storage is substituted for 50% of annual additions of gas turbine peaking capacity;
    • Scenario D assumes that annual additions of coal fired generation capacity are cut by 50%;
    • Scenario E assumes a recovery in the ratio of power demand growth to GDP growth to the level seen over the last ten years by 2030.
    • We have also modeled a combination of B and D (a 50% increase in wind and solar capacity additions and 50% decrease in coal fired capacity additions) and a combination of B, C, and D (adding the substitution of electric energy storage for 50% of gas turbine capacity additions).
  • In no scenario do we see a significant reduction in GT orders from current levels. The scenarios that pose the greatest risk (the substitution of electric energy storage for 50% of peaking capacity additions from 2025 on, and the combination of this scenario with a 50% increase in wind and solar capacity additions and a 50% decrease in coal capacity additions) are consistent with annual gas turbine orders of at least 26 GW, with growth to 33 GW by 2025 and to over 50 GW by 2030.

Exhibit 1: Base Case and Alternative Scenarios (GW)

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

Exhibit 2: SSR Forecast of Global Gas Turbine Orders and Alternative Scenarios (GW)

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

  • Upside scenarios (a 50% decrease in coal capacity additions and a recovery in the ratio of power demand growth to GDP growth to the level of the last ten years by 2030) are consistent with an increase in gas turbine orders by 2025 to 60 and 74 GW, respectively, and by 2030 to 85 and 109 GW.
  • The principal assumptions underlying our forecast are the following:
    • That annual gross additions of firm generating capacity will reflect the need to replace the capacity of retiring conventional power plants and to meet the growth in power demand;
    • That steam turbine generating stations, whether nuclear, coal, oil or gas-fired, are retired after 60 years of operation, and simple cycle and combined cycle gas turbine generators after 35 years;
    • That the ratio of power demand growth to GDP growth falls to half the level of the last 10 years;
    • That in North America, Europe and Japan, power demand does not grow at all through 2025, reflecting the time required to absorb current excess capacity, after which we assume power demand growth resumes at one half the ratio to GDP seen over the last 10 years;
    • That the requirement for firm generation capacity will be met by a combination of (i) the firm capacity value of new renewable resources (10% of nameplate for wind, 40% for solar and 55% for others), (ii) planned additions of nuclear capacity, (iii) continued growth in coal fired capacity, in those regions that have historically relied upon it, in the same proportion of gross capacity additions as seen over the last 25 years, (iv) gas turbine peakers equivalent to 20% of gross firm capacity additions, and (v) combined cycle gas turbine generators for the remainder;
    • That gas turbine orders in year reflect the average annual gas fired capacity additions forecast for years t + 2, t + 3 and t + 4.
    • Finally, we have relied upon the medium-term GDP forecasts of the Organization for Economic Co-operation and Development (OECD) and the forecast for growth in renewable and nuclear generation capacity published by the International Energy Agency (IEA).
  • In summary, we see gas turbine orders rising materially by 2030 in our base case and in all our downside scenarios, sustained by the accelerating pace of power plant retirements. Other than a change in the rate of power demand growth, our base case forecast of gas turbine orders is most sensitive to changes in technology choice (i.e., scenarios B and D, accelerating renewable capacity additions or slowing coal fired capacity additions) and to competition from electric energy storage (scenario C), which we believe could become economically competitive with gas fired peakers by 2024 (see our report Can Grid Scale Energy Storage Compete with Gas Fired Peakers? Not Yet, But Coming Soon).
  • Clients wishing to receive a copy of the Excel model and historical data underlying our forecast are invited to contact the authors of this report (see first page for contact details).

Exhibit 3: Heat Map: Preferences Among Utilities, IPP and Clean Technology

 Source: SSR analysis

Details

In our report of May 10th, The Impending Recovery in the Market for Power Generation Equipment: A Global Perspective, we estimated the trajectory of global demand for new power generation equipment over the next two decades. We did so by examining the two key drivers of demand for generation capacity: (i) the need for new generation capacity to meet the growth in global power demand, which is the key driver of demand for generation equipment in the rapidly developing economies of China, India and the Middle East, and (ii) the need to replace aging coal, nuclear and gas fired power plants, which tends to be the most important driver of demand in the mature economies of Europe, North America, and Japan. In this report, we have modified and calibrated our previous analysis to focus on the medium-term outlook for global gas turbine orders.

To estimate global growth in peak power demand we first estimated the growth in electricity consumption by region. Based on data from the U.S. Energy Information Administration, the International Energy Agency and the Organization for Economic Co-operation and Development (OECD), we have calculated for each principal region of the globe the ratio of (i) the 10-year CAGR in electricity consumption to (ii) the 10-year CAGR in real GDP. Capitalizing on the OECD’s long- term forecasts of GDP growth by region, we used these historical ratios to estimate the likely growth of regional electricity consumption (see Exhibits 4 and 5).

Exhibit 4: OECD GDP Growth Forecast Exhibit 5: Ratio of Power Demand Growth

To GDP Growth, 2006-2016

 

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

To calibrate our model to the expected level of gas turbine orders in 2018 and 2019 (~30 GW per year) we have made what we believe to be a very conservative modification to our prior forecast:

  • first, we have assumed that the long-term ratio of power demand growth to GDP growth globally falls to half the level of the last 10 years and,
  • second, we have assumed that in North America, Europe and Japan, power demand does not grow at all through 2025, reflecting the time required to absorb current excess capacity, after which we assume power demand growth resumes at one half the ratio to GDP seen over the last 10 years.

To estimate the required growth in firm generation capacity, we have assumed that load shapes and loss ratios by region are unchanging over time, so that the system requirement for firm generation capacity grows at the same rate as regional 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 by region – 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. Given these assumptions, our forecast rate of growth in firm generation capacity is identical to that of electricity consumption.

To estimate the growth in required fossil fueled generation capacity, we have adjusted our estimate of the required growth in firm generation capacity to account for (i) net changes in nuclear generation capacity over time as well as (ii) an estimate of firm capacity value of expected additions of renewable generation capacity. The International Energy Agency (IEA) provides long term forecasts by region of expected growth in renewable generation capacity, broken down into wind, solar and other renewables, as well forecasts of the expected construction or retirement of nuclear generation capacity.[1]

To estimate the fossil fueled generation capacity required in each region, we have added to our estimates of the firm generation capacity required to meet future power demand in the region the IEA’s estimates of future nuclear retirements, and have subtracted the IEA’s estimates of new nuclear generation capacity expected to be added. Next, we subtracted the firm capacity value of the renewable generation resources forecast by the IEA to be built in the region over the coming decades. The output of certain renewable generation technologies, including hydroelectric, geothermal and biomass fired power plants, can be scheduled in advance with a degree of reliability and thus can count more fully as firm capacity. Moreover, 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. We have therefore classified as firm capacity a minimum percentage, depending on the generation technology, of the IEA’s forecast renewable capacity additions, attributing a firm capacity value of 10% to wind, 40% to solar and 55% to other renewable resources, which in most regions of the world are expected by the IEA to be hydroelectric.[2]

The remaining need for firm generation capacity we have assumed is met by the construction of new coal or gas fired power plants. To estimate the share of each, we have assumed that the choice of technology in each region will replicate the proportions of coal and gas fired capacity in the region’s historical additions of fossil fuel capacity over the last ten years. In the case of China, however, the government has stated that it intends to limit total coal generation capacity to 1,100 GW, and we have respected this cap in our forecasts.

Our estimate of annual retirements of fossil fuel capacity by region is presented in Exhibit 6.

Exhibit 6: Global Retirements of Fossil Generation Capacity, by Region (GW)

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

Estimating the annual retirements of existing firm generation capacity is more complex than estimating power demand growth or the need for new firm generation capacity. In the United States, utilities and independent power generators face regulatory reporting requirements that provide a trove of information on the existing generating fleet. Specifically, the Energy Information Administration (EIA) of the Department of Energy maintains data on the capacity, primary fuel, prime mover, and commercial operation date of the ~16,000 operating and retired fossil fuel generating units in the United States. Based on the ages at retirement of already retired units, we estimated the average useful life of different types of power plants. Our estimates assume an average useful life of (i) 60 years for nuclear, coal, gas and oil-fired steam turbine generators and (ii) 35 years for gas and oil-fired combustion turbines and combined cycle gas turbine generators. Knowing the type and the commercial operation dates of the generating units currently in operation, we have estimated their likely retirement date. Finally, 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. (See our note of 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?.) [3]

Outside the United States, similarly granular information on the existing generating fleet was not readily available to us. However, IEA data on the growth in power generation capacity by region is available from 1980 on. For the years from 1980 to 1990, we assumed that these capacity additions comprised steam turbine generators, whether powered by coal, oil, gas or nuclear fuel; as in the United States, we assumed that these steam turbine generators have a useful life of 60 years. After 1990, we assumed the required capacity additions comprised a mix of steam turbines, combustion turbines and combined cycle gas turbine generators (CCGTs); as in the U.S. we assumed that the combustion turbine and CCGTs have a useful life of 35 years. We modeled the mix of steam turbines, combustion turbines and CCGTs added each year so as to arrive at a mix of these generation technologies in 2015 that reflected the actual mix of generation technologies reported in the IEA data for that year. Finally, to estimate the retirement dates of plants brought on line prior to 1980, we assumed that the age profile of each region’s generating fleet in 1980 paralleled that of the U.S. generating fleet in 1980. We then estimated the retirement dates of these units by assuming that the units will retire 60 years after their estimated date of commercial operation.

To translate our forecast of required gas-fired capacity additions into an estimate of gas turbine orders, we have made the following assumptions:

  • that 20% of gas-fired capacity additions comprise gas turbine peakers;
  • that the remaining gas-fired capacity additions comprise combined cycle gas turbine generators, ~65% of whose capacity is accounted for by the gas turbines and the remainder by the heat recovery steam generator and steam turbines; and
  • That gas turbine orders in year t reflect the average annual gas fired capacity additions forecast for years t + 2t + 3 and t + 4.

A forecast of gas turbine orders predicated on the assumptions described above – that future capacity retirements will reflect what historically has been the useful life of steam turbine and gas turbine generators, a very conservative estimate of power demand growth, and a continuation of existing patterns of technology choice — is consistent with rapid growth in gas turbine orders, which we forecast at 9.4% p.a. over 2020-2025 and 7.6% p.a. over 2025-2030, with orders rising from 31 GW in 2020 to 49 GW in 2025 and 70 GW in 2030 (see Exhibit 7)

Exhibit 7: SSR Forecast of Global Gas Turbine Orders

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

We have modeled four alternative scenarios, and two combinations thereof (see Exhibits 8 and 9). Specifically:

    • Scenario B assumes a 50% increase in the annual pace of wind and solar capacity additions;
    • Scenario C assumes that from 2025 on, electric energy storage is substituted for 50% of annual additions of gas turbine peaking capacity;
    • Scenario D assumes that annual additions of coal fired generation capacity are cut by 50%;
    • Scenario E assumes a recovery in the ratio of power demand growth to GDP growth to the level seen over the last ten years by 2030.
    • We have also modeled a combination of B and D (a 50% increase in wind and solar capacity additions and 50% decrease in coal fired capacity additions) and a combination of B, C, and D (adding the substitution of electric energy storage for 50% of gas turbine capacity additions).

Exhibit 8: SSR Forecast of Global Gas Turbine Orders and Alternative Scenarios (GW)

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

Exhibit 9: Base Case and Alternative Scenarios (GW)

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

In no scenario do we see a significant reduction in GT orders from current levels. The scenarios that pose the greatest risk (the substitution of electric energy storage for 50% of peaking capacity additions from 2025 on, and the combination of this scenario with a 50% increase in wind and solar capacity additions and a 50% decrease in coal capacity additions) are consistent with annual gas turbine orders of at least 26 GW, with growth to 33 GW by 2025 and to over 50 GW by 2030.

The most adverse of these scenarios, from the standpoint of the gas turbine manufacturers, is one in which electric energy storage becomes economic for widespread substitution of gas turbine peakers, but even there we see little downside to the current gas turbine market and eventual acceleration of growth. Were storage to displace 50% of new peaking capacity, which we estimate will be economic by 2024 (see our report Can Grid Scale Energy Storage Compete with Gas Fired Peakers? Not Yet, But Coming Soon), we estimate that gas turbine orders could fall by an average of 17 GW per year over 2026-2030 versus our base case (see Exhibit 8). A 50% increase in our forecast of solar and wind capacity additions (from an average of ~126 GW annually over 2020-2030, as forecast by the IEA, to ~196 GW) would cut gas turbine orders by ~8 GW annually from 2022 on. Conversely, a 50% decrease in coal fired capacity additions would require an offsetting increase in gas turbine orders averaging ~12 GW annually from 2022 on. Interestingly, a combination of (i) a 50% increase in wind and solar capacity and (ii) a 50% decrease in coal fired capacity additions has little long-term impact on expected gas turbine orders.

Upside scenarios (a 50% decrease in coal capacity additions and a recovery in the ratio of power demand growth to GDP growth to the level of the last ten years by 2030) are consistent with an increase in gas turbine orders by 2025 to 60 and 74 GW, respectively, and by 2030 to 85 and 109 GW.

In conclusion, we see gas turbine orders rising materially by 2030 in our base case and in all our downside scenarios, sustained by the accelerating pace of power plant retirements. The downside risk to orders, in our view, stems primarily from technological change, and in particular the potential for the substitution of electric energy storage for gas turbine peakers (scenario C). Rapid acceleration of renewable capacity growth (scenario B) also poses a risk, but we believe such a scenario would also likely include an offsetting reduction in coal fired capacity additions, significantly mitigating its impact (see the combination scenario B + D).

©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. For the U.S. market, however, we have relied on our own forecasts of nuclear retirements and renewable capacity additions. For our note of 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?we prepared our own forecast of U.S. nuclear retirements, taking into account announced retirements of U.S. nuclear power plants and assuming that the remainder will be retired 60 years after entering commercial operation. We have continued to use this forecast in the current note. Second, as the OECD forecast of U.S. renewable capacity additions was below the recent pace of renewable capacity additions, we substituted our own forecast of U.S. renewable capacity growth: 10.5 GW of new solar, 6.0 GW of new wind and 0.5 MW of other renewable capacity added annually. 
  2. In the US we attributed a firm capacity value of 85% to Other Renewables because, based on the IEA’s forecast capacity factors, they appear to be primarily baseload geothermal and biomass generation. 
  3. 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 28,000 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. 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. 
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