If This Is the Golden Age of Electric Utilities, What’s Next? Or, How Fast Can Rate Base Grow in the Long Term and on What Will Utilities Spend?

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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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October 2, 2017

If This Is the Golden Age of Electric Utilities, What’s Next?

Or, How Fast Can Rate Base Grow in the Long Term

and on What Will Utilities Spend?

Based upon the disclosed capital expenditures plans of the publicly trade U.S. regulated utilities, we expect the sector to realize 6.7% average annual growth in electric plant rate base over the five years 2016-2021, a pace consistent with ~4.5% to 5.0% annual growth in earnings per share. Given the sector’s 3.5% dividend yield, regulated utilities thus offer the prospect of ~8.0% to 8.5% average annual returns, absent a change in PE multiples, competitive with prospective returns on the S&P 500.

While our five-year forecast of 6.7% annual growth in electric plant rate base is in line with the sector’s historical performance over the last 15 years, growth in electric plant rate base has averaged less than 4% p.a. when measured over the last three decades. In this note, we explore the implications for the industry and individual utilities of capital expenditures reverting to a long run pace of growth that is closer to this historical mean. We then estimate a baseline for the long run trend of rate base growth based upon (i) utilities’ historical pace of capital expenditure in the generation, transmission and distribution segments; (ii) the rates of depreciation applied by individual companies to utility plant by segment; and (iii) the expected growth of deferred tax liabilities by company. We have sought to take into account secular changes that may speed or slow capex and rate base growth in future, such the stagnation of U.S. power demand over the last decade and the scheduled phase-out of bonus depreciation by 2020. The resulting estimates of post 2021 capex and rate base growth are best thought of as a central tendency for the industry, around which company performance will vary, but to which it may revert over time.

While our analysis suggests that capex and rate base growth could slow from current levels, we see the potential for markedly different growth trajectories for the generation, transmission and distribution segments, driven by a material shift in the composition of utility capex going forward. We assess how individual utilities may fare in the context of slowing industry growth, given their individual exposures to generation, transmission and distribution rate base and the changing growth prospects of each. Finally, we consider the possibility that distribution capex could materially exceed the historical trend and our baseline estimate.

  • The disclosed capex plans of the publicly traded utilities for 2017-2021 point to a large increase in capital expenditures on distribution, modestly declining outlays on transmission, and a significant contraction in generation capex – together driving ~6.7% annual growth in rate base.
    • As a share of total utility capex, we expect distribution capex to rise from 34% of the total over the last five years (2012-2016) to 46% of the total over the next five (2017-2021); the share of transmission capex is to remain relatively stable at 28%; and investment in generation to decline markedly, from 38% to 26% of the total (see Exhibits 6 and 7).
  • Beyond 2021, a reversion of industry capex to its historical trend would imply slowing growth in net utility plant; partially offsetting the impact on rate base, however, will be slower growth in deferred taxes, reflecting the scheduled phase-out of bonus depreciation by 2020 and the roll-off of deferred taxes accumulated during the years of high investment following the turn of the century. Our model suggests these opposing trends could be consistent with long run growth in the industry’s electric plant rate base of 4.5% to 5.3% p.a. (see Exhibit 1).
  • Within the sector, our estimates of the long run trends in segment capex drive divergent trajectories of rate base growth by segment (6.0% p.a. for distribution, 6.2% for transmission, and 3.8% for generation; see Exhibit 2) that in turn shape the outlook for individual utilities.

Exhibit 1: Growth in Electric Rate Base Exhibit 2: Rate Base Growth by Segment

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Source: SNL, FERC Form 1, SSR analysis

  • Exhibit 12 presents our estimates of growth in electric plant rate base by company for the years 2021-2025. The utilities with the most rapid expected rate base growth, per the results of our model, are CMS (6.5% p.a., against an industry average of 5.4% p.a.), AEP (6.4%), AVA (6.2%), DTE (6.2%), EE (6.2%) and DUK (6.1%). Expected to grow least rapidly are POR (2.8% forecast annual growth in electric plant rate base over 2021-2025, as against an industry average of 5.4% p.a.), LNT (3.4%), EIX (4.3%), ES (4.6%), OGE (5.0%), and XEL (5.0%).
  • While rate base growth is expected to slow across the industry over 2021-2025, several utilities show particularly marked declines in their relative rankings. Among the utilities that rank in the top two quintiles on forecast rate base growth over 2018-2021, but which may fall into the bottom two quintiles over 2021-2025 are EIX (second quintile over 2018-2021, falling to fifth over 2021-2025), LNT (first to fifth), NWE (first to fourth), PPL (second to fourth) and XEL (second to fifth). Conversely, EE’s and GXP’s relative rankings on rate base growth shows a marked improvement from 2018-2021 to 2021-2025.
  • Technological developments and changing regulatory priorities point to the potential for materially higher levels of distribution capex, and more rapid growth in distribution rate base, than have been typical over the last 30 years. The utilities with the highest share of distribution to total electric plant rate base are first and foremost ED, whose distribution rate base comprises 82% to total electric plant rate base, followed by ES (55%), EIX (54%), CMS (51%), PCG (50%) and HE (49%). Among the hybrid utilities, EXC and CNP have particularly high ratios of distribution to total rate base, at 74% and 69%, respectively, followed by AGR and FE (58% and 57% respectively). For ES and EIX, in particular, this could result is materially faster rate base growth than our baseline forecast (Exhibit 16.)
  • What are the financial implications of a slowdown in rate base growth from the 6.7% annual rate forecast for 2016-2021 to a long term trend rate of ~5.0%?  
    • The average allowed ROE set by state regulators in electric utility rate cases over the last four quarters has been 9.7%.  Given the utility industry’s average dividend payout ratio of 65%, this allowed ROE, if realized by the industry, would permit retained earnings to grow at 3.4% p.a.
    • Given the static capital structure of the industry, with utilities’ ratio of equity to rate base fixed by regulators, rate base growth in excess of 3.4% requires utilities to augment their equity through share issuance.  A slowdown in rate base growth will likely be reflected, therefore, in a reduction in equity issuance and the consequent dilution of earnings per share.  Shareholders’ total return should thus fall far less than the change in rate base growth.
    • However, given that utilities’ allowed returns on equity significantly exceed their cost of equity (estimated at ~6.0%, based on the industry’s long run equity beta of 0.5), existing shareholders will lose the excess returns that they would have earned on higher levels of rate base.  Given the 400 b.p. gap between utilities’ ~10% allowed return on equity and ~6% cost of equity, we estimate that for every 1.0% reduction in potential rate base, and thus owners’ equity, the consequent erosion of shareholder returns is ~0.4%.
    • The ~170 b.p. decline in rate base growth estimated here, therefore, would be expected to reduce shareholder returns by ~70 basis points.
  • Investors interested in pursuing the issue of rate base growth with utility management teams directly are encourage to join us in meetings with the management teams of AEE, AEP, DUK, ED, EIX, ES, ETR, EXC, FE, LNT, NEE, PCG, PEG, PNW, WEC, XEL at the EEI Financial Conference in Orlando on November 5-7.

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

Source: SSR analysis

Details

The Investment Case for the Regulated Utilities

In our note of September 6, 2017, Rising Growth and Falling Beta: Electric Utility Rate Bases Show Accelerating Growth Through 2021,[1] we provided our forecast of growth in electric plant rate base for U.S. publicly traded, regulated utilities over the five years from 2016 through 2021. Based on the announced capital expenditures plans of the publicly traded U.S. utilities, as well as our estimates of the growth in accumulated depreciation and deferred liabilities at these companies, we expect U.S. publicly traded utilities to expand their combined electric plant rate base at average annual rate of 6.7% over the next five years (see Exhibit 4). This is line with the pace of growth in aggregate electric plant rate base over the last decade (6.7% over 2006-2016), and represents a slight acceleration in the pace of growth over the last five years (6.3% over 2011-2016).[2]

Exhibit 4: Historical Growth in the Aggregate Electric Rate Base of U.S. Investor Owned Utilities, and SSR’s Estimate of Rate of Base Growth for U.S. Publicly Traded Utilities (2016-2021E)

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1. For an explanation of our forecast methodology, please see footnote 2 above.

Source: FERC Form 1, SEC 10-Q, SNL, SSR analysis

Historically, 6.7% annual growth in electric plant rate base has been consistent with ~4.5% to 5.0% annual growth in utilities’ earnings per share. Given the sector’s 3.5% dividend yield, regulated utilities thus offer the prospect of ~8.0 to 8.5% average annual returns (absent a change in PE multiples), prospective returns that we believe to be competitive with those on the S&P 500. Given the historically low beta of the regulated utility sector currently (only 0.26x over the last 12 months; see Exhibit 5), we find the sector compelling. Given their current expected returns and beta, regulated utilities can significantly mitigate portfolio volatility without sacrificing portfolio returns.

Exhibit 5: Beta of the Philadelphia Utility Index Relative to the S&P 500 (1)

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1. The Philadelphia Utility Index is comprises primarily regulated electric and regulated electric and gas utilities.

Source: Bloomberg and SSR analysis

What Will Drive Future Growth in Utility Rate Base?

To assess the potential future growth of the utility industry’s electric plant rate base, we have prepared estimates, for each of the publicly traded electric utilities, of (i) additions to gross generation, transmission and distribution plant; (ii) the increase in accumulated depreciation by segment, on the basis of which we can calculate the growth of net utility plant in service; and (iii) the growth of utilities’ deferred tax liabilities, which utility regulators offset against net utility plant in the calculation of regulated rate base.

For the next five years (2016-2021), our estimates of additions of gross generation, transmission and distribution plant are based upon the capital expenditure plans of each of the publicly traded regulated utilities, as disclosed in their SEC filings and management presentations.

Longer term (2022-2025), our estimates of gross plant additions by segment are based upon the assumption that utility capex by segment will gradually revert to the industry’s long term historical trend. (In the Appendix, we discuss in detail how we derive these long-run estimates of normalized capex by segment.) We note that numerous factors could cause individual utilities’ capital expenditures to vary from our estimate of the long-run industry norm, and thus for their growth in rate base to diverge from our baseline estimate. Our estimates of post-2021 capex are best understood, therefore, as attempts to model a central tendency for the industry around which company performance will vary, but to which it may revert over time.

Taken in the aggregate, however, our medium term forecast (2016-2021) and longer term estimate (2022-2025) of capital expenditures suggest that the industry is entering a period when capital expenditures by segment will shift significantly, favoring distribution over generation and transmission. We estimate that distribution capex is poised to grow at a 3.3% average annual rate from 2016 through 2025, while transmission capex will expand at only 0.9% annually and generation capex will decline by 0.1% p.a. (see Exhibit 6). As a share of total utility capex, therefore, we expect distribution capex to rise from 34% of the total over the last five years (2012-2016) to 46% of the total over the next five (2017-2021). While transmission’s share of capex is expected to be relatively stable at 28%, investment in generation will decline markedly, from 38% to 26% of the total (see Exhibit 7).

The shift in capital expenditures from generation – a sector characterized by high permitting, construction, regulatory and financial risk[3] — to distribution, where these risks are minimal, could significantly reduce the risk to shareholders of utilities’ capex plans. It will also have material impact on the relative rates of growth of the various publicly traded utilities, which may accelerate or decelerate depending on the segment breakdown of their existing rate base (see Exhibit 12).

Exhibit 6: Estimated Capital Expenditures by Segment of the Publicly Traded U.S. Regulated Utilities, 2016-2025 ($ Billions)

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1. For an explanation of our forecast methodology, please see footnote 2 above and the Appendix.

Source: SNL, FERC Form 1, SSR analysis and estimates

Exhibit 7: Estimated Composition of Aggregate Capital Expenditures on Electric Plant by Segment (1)

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1. For 2012-2016, our estimates of capex by segment are based upon the annual additions of gross utility plant in the generation, transmission and distribution segments, aggregated across all U.S. investor owned, regulated utility operating companies. For 2017-2021, our capex estimates reflect the disclosed capital expenditure plans by segment of the publicly traded, U.S. investor-owned regulated utilities.

Source: SNL, FERC Form 1, SSR analysis and estimates

The shift in industry capex from generation to distribution leads us to expect more rapid future growth in distribution plant in service, while we expect growth in generation and transmission plant in service to slow. Growth in net distribution plant in service, which averaged 5.0% p.a. over the last ten years (2006-2016), is expected to accelerate to 6.4% p.a. over 2016-2025. Growth in net transmission plant, by contrast, is expected to decelerate from 11.2% p.a. over the last ten years to 7.3% p.a. over 2016-2025, while growth in net generation plant decelerates from 8.0% p.a. to 5.0% p.a. The estimated trajectories of net utility plant in service by segment are illustrated in Exhibit 8.

Exhibit 8: Estimated Net Utility Plant in Service by Segment of the Publicly Traded U.S. Regulated Utilities, 2016-2025 ($ Billions)

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1. For an explanation of our forecast methodology, please see footnote 2 above as well as pages 18 and following.

Source: SNL, FERC Form 1, SSR analysis and estimates

When calculating regulated rate base, U.S. utility regulators generally deduct utilities’ net deferred tax liabilities from their net utility plant in service. The increase in deferred taxes associated with a particular level of capital expenditure will vary over the years due to changes in tax incentives, such as bonus depreciation, and in corporate tax rates. Also important is the roll-off of deferred taxes booked in the past, which in turn are function of historical rates of investment. Over the long run, therefore, our estimates of the rate of growth in electric plant rate base will differ somewhat from the expected trajectory of net utility plant. (For a detailed explanation, see pages 20 and following.)

Our long run estimate of the growth in utilities’ electric plant rate base reflects the combined impact of two opposing trends: (i) the expected slowdown in the growth of net utility plant, as the rate of plant additions slows from the pace of recent years to converge with its long run trend, and (ii) a reduction in the annual accumulation of deferred tax liabilities as bonus depreciation is phased out. Current tax law provides for the rate of bonus depreciation to fall from 50% in 2017 to 40% in 2018 and 30% in 2019 before being phased out altogether in 2020 (see Exhibit 21). The phase-out of bonus depreciation will cause the annual increase in utilities’ deferred tax liabilities to slow over 2018-2019, and to fall dramatically in 2020 (see Exhibit 9). The phase-out of bonus depreciation is expected in particular to benefit the growth of generation rate base. Transmission and distribution rate base will also benefit, but less so; in these segments, the repair deduction, which is expected to be an ongoing feature of the tax code, will continue to drive growth in deferred tax liabilities, tending to slow rate base growth. (For a detailed discussion of the expected trajectory of utilities’ deferred tax liabilities, including the impact of the repaid deduction, see pages 21 and following).

Exhibit 9: Estimated Annual Drag on the Growth of Aggregate Rate Base

from the Growth of Deferred Tax Liabilities (As % of Rate Base)

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Source: SNL, FERC Form 1, SSR analysis and estimates

Exhibit 10 compares (i) the average annual rate of growth in utility plant rate base by segment over the last five years with (ii) our forecast of rate base growth over 2016-2021, which is based upon utilities’ disclosed capex plans by segment, as well as (iii) our baseline estimates of long run rate base growth, which assume that gross plant additions by segment revert to the long term industry trend. (For a detailed discussion of how we have developed our estimates of the normalized rates of gross plant additions by segment, please see the appendix to this note.)

Based on the announced capital expenditure plans of the publicly traded utilities over 2016-2021, the pace of growth in transmission rate base is expected to fall sharply, from 12.0% p.a. over the last five years (2011-2016) to just 6.5% p.a. over the next five (2016-2021). Generation rate base is expected to grow at a similar pace to the recent past, decelerating only slightly from 5.7% p.a. over the last five years to 5.6% p.a. over the next five. The rate of growth in distribution rate base, by contrast, is expected to accelerate markedly, from 4.1% p.a. over the last five years to 6.4% p.a. over the next five.

From 2022 on, we assume that gross plant additions by segment gradually converge with the long term industry trend. Were this to occur, the average annual rate of growth in transmission and distribution rate base would remain broadly constant over 2021-2025, at 6.5% and 6.4%, respectively. Our estimates of the long run growth in rate base in these segments is only slightly below these levels, at 6.2% and 6.0%, respectively. By contrast, we believe that the rate of growth in generation rate base may slow markedly, from 5.6% p.a. over 2016-2021 to 4.7% p.a. over 2021-2025 and to 3.8% p.a. over the long term. (This estimate of long term growth in generation rate base is the average of our high and low cases; see page 26 for an explanation of the alternative estimates). (See Exhibit 10).

Exhibit 10: Historical and Forecast Growth in Electric Plant Rate Base by Segment (1)

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1. The estimate of long term growth in generation rate base presented in this graph is the average of our high and low cases. For an explanation of these alternative estimates, please see page 26.

Source: SNL, FERC Form 1, SSR analysis and estimates

Based on these estimates of rate base growth by segment, Exhibit 11 presents our estimates of the future growth in aggregate electric plant rate base. Over the next five years (2016-2021), the capital expenditure forecasts provided by the managements of the publicly traded utilities are consistent with growth in aggregate electric plant rate base of 6.7% p.a. Over the period from 2021 through 2025, when management capex forecasts are no longer available, we assume that plant additions follow a glide path from the level implied by utilities’ announced capex plans to our long-term baseline estimate; over these years, our model suggests that growth in aggregate electric plant rate base will fall to a range of 4.9% to 5.4% p.a.[4] From 2025 on, our model implies a further deceleration to our long run baseline estimate of 4.5% to 5.3% annual growth in rate base, reflecting the upper and lower ends of our range of estimates for generation plant additions.

Exhibit 11: Historical and Forecast Growth in Electric Plant Rate Base

of Investor-Owned Regulated Utilities in the United States (1)

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1. The range of growth rates for 2021-2025 and the long term reflects the upper and lower ends of our range of estimates for the growth of generation rate base. For an explanation of these alternative estimates, please see page 26.

Source: SNL, FERC Form 1, SSR analysis and estimates

At the company level, our estimates of the sustainable long-term growth in rate base by segment (6.0% p.a. for distribution, 6.2% for transmission, and 3.8% for generation; see Exhibit 10) are reflected in divergent trends in long term rate base growth by company due to differences in the segment breakdown of rate base at the various utilities. Note that individual company growth rates also reflect the varied impact of deferred taxes. The increase in deferred taxes associated with a particular level of capital expenditure will vary company to company, reflecting the ability to take advantage of certain tax incentives, such as the repair deduction, and differences in corporate tax rates. More importantly, the roll-off of deferred taxes from prior years can vary markedly, reflecting how long ago major capital expenditures were made, and the tax incentives prevailing at the time. The impact of deferred taxes on rate base growth can thus vary materially from utility to utility, which can result in unexpected rate base growth results.

Exhibit 12 presents our forecasts of growth in electric plant rate base by company, including a baseline estimate for the years 2021-2025. The utilities that stand out as having the most attractive potential for long run growth in electric plant rate base are CMS (6.5% estimated annual growth in electric plant rate base over 2021-2025, as against an industry average of 5.4% p.a.), AEP (6.4%), AVA (6.2%), DTE (6.2%), EE (6.2%) and DUK (6.1%). The utilities that stand out as having particularly poor long run growth potential, per the results of our model, are POR (2.8% forecast

Exhibit 12: Historical and Forecast Growth in Electric Plant Rate Base, 2016-2025

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1. All rate base forecasts based on SSR’s estimate of aggregate capital expenditures on electric utility plant offset by SSR’s estimate of depreciation and the growth in deferred tax liabilities. For 2011-2016, we have calculated electric plant rate base using the FERC Form 1 filings of all U.S. investor-owned, regulated utility operating companies. For 2016-2021, our capex estimates reflect the disclosed capital expenditures plans of the publicly traded, U.S. investor-owned regulated utilities. For the long term, our capex estimates reflect the median of the ratio of aggregate gross plant additions to property, plant and equipment, broken down into transmission, distribution and generation, for U.S. investor owned regulated utility operating companies over 1988-2016. For 2021-2025, we have assumed a glide path in the growth of capital expenditures from the levels in managements’ forecasts to the levels we forecast for the long term.

Source: SNL, FERC Form 1, SSR analysis and estimates

annual growth in electric plant rate base over 2021-2025, as against an industry average of 5.4% p.a.), LNT (3.4%), EIX (4.3%), ES (4.6%), OGE (5.0%), and XEL (5.0%).

While rate base growth is expected to slow across the industry from 2018-2021 to 2021-2025, several utilities show the potential for particularly marked declines in their relative rankings. Among the utilities that rank in the top two quintiles on forecast rate base growth over 2018-2021, but which may fall into the bottom two quintiles over 2021-2025 are EIX (second quintile over 2018-2021, falling to fifth over 2021-2025), LNT (first to fifth), NWE (first to fourth), PPL (second to fourth) and XEL (second to fifth). Conversely, EE’s and GXP’s relative rankings on rate base growth shows a marked improvement from 2018-2021 to 2021-2025

Both the announced capital expenditure plans of the publicly traded utilities over 2017-2021, as well as our own estimates of the long term trend in distribution capex, point to an acceleration of investment in the sector in the coming years. Further, a qualitative assessment of technological change in the sector, and its potential implications for the distribution grid, suggest that there may be upside to the trajectory suggested by our qualitative analysis. We will conclude this section, therefore, with a discussion of the growth potential in distribution and which companies would benefit most if it were realized.

As illustrated in Exhibit 6, the announced capital expenditure plans of the publicly traded utilities foresee a substantial increase in distribution spend in 2017. Per these plans, aggregate utility capex on distribution plant should increase by 14% in 2017 and continue to expand in 2018, albeit more slowly. Thereafter, distribution capex is expected to plateau at $32-$33 billion annually. By contrast, transmission capex rises in 2017 but then enters a multi-year decline, falling form $21.8 billion in 2018 to $18.8 billion by 2021 (see Exhibit 13), a drop of 14%. Planned capital expenditures on generation fall more precipitously, dropping 22% from $20.8 billion in 2017 to $16.3 billion in 2021.

To some extent, this acceleration in distribution capex, and decline in planned annual capex on transmission and generation, reflects a reversion to mean in growth rates that were on an unsustainable path. As illustrated in Exhibit 14, gross plant additions in the generation and transmission segments have grown at compound annual rates of 10.6% and 13.9%, respectively, for the last eighteen years. Conversely, utilities’ planned increase in distribution capex may seek to offset the impact of eighteen years of much more modest growth; distribution gross plant additions grew at only 5.7% p.a. over this period.

Having grown as long and as rapidly as they have, transmission and generation rate base now comprise relatively high proportions of total electric plant rate base, while the share of distribution rate base is at its lowest level in 25 years (see Exhibit 15). At 26%, the share of transmission plant to total electric plant rate base has never been higher; its average share of total rate for the period 1988-2016 is only 19%. Generation’s share of aggregate electric plant rate base has been on an upswing for the last 15 years and is now close to its 1988-2016 average of 34% during a period when electric demand has stagnated. By contrast, the share of distribution in total electric rate base, at 41%, is at its lowest level since 1991 and well below its 1988-2016 average of 47%

Exhibit 13: Estimated Annual Change in Capital Expenditures by Segment

of the Publicly Traded U.S. Electric Utilities, 2016-2025 ($ Billions)[5]

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1. For an explanation of our forecast methodology, please see footnote 2 above as well as pages 18 and following.

Source: SNL, FERC Form 1, SSR analysis and estimates

Exhibit 14: Historical Growth in Gross Additions of Electric Plant by Segment (1)

1. Annual gross additions of electric utility plant, in aggregate across all U.S. investor owned, regulated utility operating companies. Note that total electric plant comprises not only generation, transmission and distribution plant but also common plant, general plant and intangible plant.

Source: SNL, FERC Form 1, SSR analysis and estimates

Exhibit 15: Breakdown of U.S. Investor-Owned Utilities’ Aggregate Utility Plant Rate Base into Its Generation, Transmission and Distribution Segments, 1988-2016

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Source: SNL, FERC Form 1, SSR analysis and estimates

Finally, technological developments and changing regulatory priorities point to the potential for materially higher levels of distribution capex, and more rapid growth in distribution rate base, than have been typical over the last 30 years. Many utilities across the country are upgrading their distribution systems through the deployment of smart grid technologies, such as customer meters capable of measuring electricity consumption by the minute and wirelessly communicating this data to the utility; devices that allow major pieces of equipment, such as transformers and substations, to be continuously monitored for signs of impending failure, allowing maintenance to be conducted on an as-needed basis as opposed to on a calendar schedule; and sensors, relays and switches that allow distribution circuits to which the supply of power has been interrupted to be supplied from alternative sources. The deployment of these technologies has had the effect of also increasing utility spending on computing and software for data analysis.

Even in the absence of these upgrades, the rising cost to customers of distribution system outages, as computers and portable electronic devices have become increasingly important, has caused regulators to impose higher reliability standards. Utilities have accelerated maintenance and replacement capex to reflect the mean-time-to-failure of critical components of the distribution grid. Utilities on the Atlantic and Gulf coasts are also spending significant amounts of capital on the storm hardening of their distribution grids, including the deployment of concrete power poles and the undergrounding of distribution lines. Lastly, we expect distribution upgrades to continue in the years ahead as the grid integrates an increased amount of distributed generation, distributed storage and electric vehicles, whose charging will require increased transformer capacity, upgraded distribution circuits, and two-way communication capability to stagger charging loads.

If these technological developments and changing regulatory priorities indeed cause distribution capex to exceed the industry’s historical trends in the years ahead, the beneficiaries are likely to be those regulated utilities for whom distribution rate base represents the largest share of total electric plant rate base. We rank the regulated utilities on this basis in Exhibit 16. The utilities with the highest share of distribution to total electric plant rate base are first and foremost ED, whose distribution rate base comprises 82% to total electric plant rate base, followed by ES (55%), EIX (54%), CMS (51%), PCG (50%) and HE (49%).

Among the hybrid utilities, EXC and CNP have particularly high ratios of distribution to total rate base, at 74% and 69%, respectively, followed by AGR and FE (58% and 57% respectively), and PEG and NEE (39% and 31%, respectively).

Exhibit 16: Relative Importance of Distribution Rate Base to the Regulated U.S. Utilities

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Source: SNL, FERC Form 1, SSR analysis and estimates

Forecasting Long Run Growth Using Historical Growth in Electric Utility Plant by Segment as a Guide

In the rest of this note, we provide the data and analyses that underpin our estimates of the sustainable, long run pace of gross plant additions and rate base growth by segment. Our estimates based upon (i) utilities’ historical pace of capital expenditure in the generation, transmission and distribution segments; (ii) the rates of depreciation applied by individual companies to utility plant by segment; and (iii) the expected growth of deferred tax liabilities by company. We have sought to take into account secular changes that may speed or slow rate base growth in future, such as the phase-out of bonus depreciation and the stagnation of U.S. power demand. Our analysis suggests the potential for markedly different long term growth trajectories for the generation, transmission and distribution segments, and thus a changing composition of utility capex going forward. We have also assessed how individual utilities may fare in the context of slowing industry growth, given their individual exposures to the generation, transmission and distribution segments and the changing growth prospects of each.

To estimate what a reversion to mean in rate base growth might look like, our first step was to measure the historical pace of gross additions of utility plant in each of the generation, transmission and distribution segment and, on this basis, to estimate the trajectory of future investment by segment. As explained below, these forecasts, while based on the historical average rate of gross plant additions by segment, also take into account the impact of secular changes in the industry that could have a material effect on capex budgets going forward. We then modeled the growth of accumulated depreciation, applying the depreciation rates applied by each of the electric utilities to the three categories of utility plant. Finally, we modeled the accumulation of deferred tax liabilities by utility. To do so, we modeled the impact of the changing to existing tax incentives over time for each category of utility plant, including bonus depreciation, accelerated depreciation and the repair deduction.

In Exhibit 17, we consider the historical trajectory of the generation segment, in aggregate across all U.S. investor owned utilities. The blue columns in the chart represent gross additions of generation plant, the red columns the annual depreciation expense attributable to generation plant, and the green columns the difference between the two. These columns are to be read off the left hand axis of the chart. The purple line, which corresponds to the right hand access, tracks net generation plant in service over time.

Exhibit 17: Generation Segment Net Plant in Service Compared to Gross Plant Additions and Depreciation Expense by Year, 1988-2016 ($ Billions)

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Source: SNL, FERC Form 1, SSR analysis and estimates

As Exhibit 17 illustrates, gross additions of generation plant declined by approximately two thirds over the ten years from 1988 through 1998, falling from a level that was approximately twice that of segment depreciation expense in 1988 to just a fraction of depreciation expense in 1998. The difference between the two, or net investment in generation plant, turned negative in 1992 and remained so for ten years. As a result, net generation plant in service declined steadily from its 1992 peak through 2002. Beginning in 2003, however, gross additions of generation plant began a decade of rapid growth, driving positive net investment in generation and an upswing in net generation plant in service that has continued through 2016.

What accounts for the swings in investment in generation plant over this period, and the consequent relatively slow growth in net generation plant in service through the cycle (1.2% p.a., on average, over 1988-2016)? Over the ten years from 1988 through 1998, gross annual additions of generation plant fell at a 11.9% compound annual rate, reflecting an overbuild of generation capacity over the prior two decades as well as write-offs and a hesitance to spend in the face of potential deregulation of generation in a large number of U.S. states. From 1970 through 1987 the United States doubled its generation capacity, while power demand rose by only two thirds as demand growth decelerated after construction began on large generation projects, many of them nuclear. Electricity rates rose rapidly over this period, not only to recover the cost of the new capacity, but also to offset materially higher fuel costs, reflecting the oil price shocks of the 1970s and the deregulation of natural gas prices in the 1980s. By the 1990s, this sharp increase in the cost of electricity had caused many states to consider breaking the monopoly of the regulated utilities and introducing competition through the deregulation of generation. Backed by ample reserve margins and faced with the prospect that incremental investment in generation might not be recoverable in regulated rates, utilities chose not to invest and, in some cases, wrote off portions of existing plant.

The years from 1998 through 2016, by contrast, saw an upswing in generation capex, with gross additions of generation plant expanding at a 10.6% compound annual rate. Several factors contributed to the recovery of utility investment in generation. First, in 1998-2000, price spikes hit wholesale power prices in a number of markets, particularly in the Midwest, as reserve margins dropped into single digits. Second, the winter of 2000-2001 saw repeated rolling blackouts in northern and southern California, which, on April Fool’s Day 1995, had been the first state to deregulate power generation. Following the California energy crisis, state initiatives to deregulate generation came to an end. The overbuild of generation capacity over the prior two decades had gradually been absorbed, and the tight reserve margins now loomed in multiple regions. A third important factor was the increasingly stringent EPA air emissions regulations for sulfur dioxide, nitrogen oxides, mercury, and acid gases, which forced the installation of emissions controls across the coal and oil-fired generation fleets. The high cost of these environmental upgrades ultimately forced the retirement of some 15% of U.S. coal fired capacity, encouraging utility investment in new gas fired generation capacity.

Exhibit 18 presents the historical trajectory of utility investment in transmission over from 1988 through 2016. Over this period, net transmission plant in service grew at a compound annual rate of 6.3%, faster than both generation (1.2% p.a., on average over the period) and distribution (5.1% p.a.). While utility capex on transmission was weak through the 1990s, it remained consistently in excess of segment depreciation so that net transmission plant in service continued to grow. Following a pattern very similar to generation, transmission capex began to recover in 1999 and then accelerated markedly from 2006 on (compare Exhibits 17 and 18). In part, this is an echo of the trend in gross additions of generation plant, with new power plant construction driving investment in switchyards, transformers and connections to the transmission grid. Transmission investment was also affected by policy initiatives linked to the deregulation of generation. The creation of competitive regional power markets required power grids originally designed to serve vertically integrated utilities to be integrated with each other, allowing the wheeling of power across much larger regions. FERC Order No. 2000, issued in December, 1999, encouraged the formation of independent system operators to manage regional transmission systems on an open-access basis, allowing newly deregulated power plants to move power outside their former service territories and supply the retail customers of neighboring utilities. Second, the Northeast power blackout of August 2003, which was triggered by transmission rather than generation failures, created an impetus for transmission upgrades to enhance system reliability. Finally, in response to these developments, the Energy Policy Act of 2005 sought to accelerate investment in the bulk power grid by granting FERC the authority to grant incentive ROEs on new transmission projects. FERC used this power liberally in the decade that followed to stimulate the integration of regional power grids and enhance system reliability.

Exhibit 18: Transmission Segment Net Plant in Service Compared to Gross Plant Additions and Depreciation Expense by Year, 1988-2016 ($ Billions)

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Source: SNL, FERC Form 1, SSR analysis and estimates

The distribution segment has historically shown the steadiest growth in net utility plant, with gross plant additions consistently exceeding depreciation over 1988-2016, driving 5.1% compound annual growth in net distribution plant in service (see Exhibit 19).  The major state and federal policy initiatives of the 1990s and 2000s – the deregulation of generation, the control of air emissions from coal fired power plants, the formation of regional transmission networks – had no impact on the distribution sector, which as a consequence shows none of the policy-induced cyclicality of the generation and transmission segments. Unlike generation, moreover, the segment is not vulnerable to the over-estimation of demand that caused the U.S. generation to be materially over-built in the 1970s and 1980s and to lag in the decade that followed; whereas the permitting and construction of nuclear and coal fired power plants must be put in motion five to ten years before their capacity is needed, distribution networks grow organically as new customers are connected to the grid.

Exhibit 19: Distribution Segment Net Plant in Service Compared to Gross Plant Additions and Depreciation Expense by Year, 1988-2016 ($ Billions)

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Source: SNL, FERC Form 1, SSR analysis and estimates

The Other Key Drivers of Rate Base: Accumulated Depreciation & Deferred Tax Liabilities

Offsetting gross plant additions in the calculation of regulated rate base is the annual accumulation of depreciation expense. We have estimated depreciation expense on a company by company basis, applying the rates of depreciation for generation, transmission and distribution plant used by the various regulated utility operating companies in the preparation of their Form 1 financial statements.

A further offset to gross plant additions is the accumulation of deferred tax liabilities, which are deducted from plant in service in the calculation of regulatory rate base. In recent years, the growth in net deferred tax liabilities has acted as a drag on the rate base growth of U.S. regulated utilities. From 2012 through 2017, the IRS has permitted companies to depreciate 50% of gross plant additions in the first year of operation (“bonus depreciation”). The remaining 50% of the value of gross plant additions may be depreciated on an accelerated basis, usually, in the case of utility plant, over a period of 20.5 years using the Modified Accelerated Cost Recovery System (MACRS) permitted by IRS regulations. By contrast, in the preparation of their regulatory financial statements, U.S. regulated utilities are required to depreciate plant in service over its estimated economically useful life, which usually extends over 30 to 40 years. The more rapid depreciation of plant in service for tax than for book purposes results in utilities paying much lower cash taxes than are recognized in their financial statements. As cash taxes paid are materially less than the provision for income taxes on utilities’ regulatory books, utilities must book a deferred tax liability for the difference. The difference between tax and GAAP depreciation expense for a hypothetical utility investment when bonus depreciation is available, and the consequent build-up in deferred tax liability, is illustrated in Exhibit 20.

Exhibit 20: The Difference Between Book and Tax Depreciation and the Consequent Build-Up and Reversal of the Deferred Tax Liability Associated with a Utility Asset (1)

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1. Assumes 50% bonus depreciation and MACRS

Source: IRS and SSR analysis

In later years, the situation reverses; the utility’s tax books, on which accelerated depreciation has been applied, will show the asset to be fully depreciated, while for regulatory accounting purposes depreciation expense will continue to be recorded until the end of the asset’s useful life. As a result, the utility’s regulatory accounts will show higher depreciation expense, and lower taxable income and income tax expense, than will its tax books. The utility’s book provisions for income taxes will therefore fall short of its actual cash taxes. The utility then begins to reverse its deferred tax liability, amortizing it to offset the excess of cash taxes over book income tax expense (see Exhibit 20).

Importantly, current tax law provides for the rate of bonus depreciation to fall from 50% in 2017 to 40% in 2018 and 30% in 2019 before being phased out altogether in 2020 (see Exhibit 21). The phase-out of bonus depreciation will cause the annual increase in utilities’ deferred tax liabilities to slow over the next two years, and to fall dramatically in 2020. We illustrate this effect in Exhibit 22, where the red bars represent the percentage reduction in aggregate electric plant rate base each year as a result of the increase in deferred tax liabilities attributable to new plant placed in service. This headwind to rate base growth falls from an estimated 3.3% of aggregate electric plant rate base in 2017 to just 1.0% in 2020 and 2021.

By contrast, the reversal of deferred tax liabilities associated with older assets, which are now fully depreciated for tax purposes, constitutes a tailwind to rate base growth, and this tailwind continues largely unabated over the remainder of the decade (see the blue columns in Exhibit 22). The net impact of deferred taxes on rate base, illustrated by the green columns in Exhibit 22, is thus expected to transition from a material headwind to rate base growth (equivalent to 1.8% of aggregate electric plant rate base in 2017) to almost neutral by 2020.

Exhibit 21: Bonus Depreciation Rates by Year

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Source: Internal Revenue Service

Exhibit 22: Estimated Annual Change in Aggregate Rate Base of U.S. Regulated Electric Utilities Attributable to Changes in Deferred Taxes

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Source: IRS and SSR analysis

That utilities should continue to book significant deferred tax liabilities in respect of new plant additions, despite the phase-out of bonus depreciation, reflects the continued use of MACRS accelerated depreciation schedules for tax purposes as well as a second equipment-related tax deduction, the repair deduction. The IRS generally requires all investment in property to be capitalized. However, IRS regulations adopted in final form in 2013 allow businesses to deduct, rather than capitalize, the cost of repairs to property used in carrying on their trade or business. As a result of the new rules, utilities are now able to deduct for tax purposes a substantial portion of their maintenance capex.

Per the IRS’ regulations, maintenance expenditures may qualify as a deductible cost of repair only if their cost is not material relative to the value of the system being repaired (e.g. <10%). In addition, to be deductible, repairs must not (i) restore the property to its original state; (ii) substantially prolong the useful life of the property repaired; or (iii) adapt the property to a new or different use. Various characteristics of utility plant militate in favor of repair costs being classified as deductible under the IRS’ rules. First, utility plant, and particularly transmission and distribution networks, is made up of large, expensive and complex systems with multiple components; as a result, the cost of repairing individual components frequently falls below 10% of the system’s value and therefore is not deemed material. Second, repairs to the individual components of such large, complex systems do not restore the system as a whole to its original state or materially extend its useful life. Third, electric utility plant is dedicated to a single purpose, the supply of electricity; repairs will not change this. Utilities have thus been successful in deducting a significant part of their maintenance capex on their transmission and distribution networks. Utilities have been less successful in categorizing the maintenance of power plants as deductible repairs, largely because the cost of individual components of power plants, such as a boiler, turbine or generator, are often material relative to the power plant as a whole. One implication of this difference is that the build-up of deferred tax liabilities will constitute a more significant headwind to the long run growth of transmission and distribution rate base than to generation rate base. In our forecast, therefore, we estimate the build-up in deferred tax liabilities by segment and by company, based on the composition of capital expenditures and the effective tax rate of each utility.

Methodological Appendix: Our Estimates of Long Run Potential by Segment

In this Appendix, we explain how we have estimated the trajectory of gross plant additions and the growth of net utility plant in service from the historical data presented in Exhibits 17 through 19

We have seen that, historically, the expansion of generation plant has been driven by utilities’ confidence in their ability to recover their investments in regulated rates, the relationship between installed capacity and power demand, and, particularly in recent years, by the capital expenditures required to comply with increasingly stringent EPA air emissions regulations. While state deregulation of generation is no longer a concern, we believe the other two growth drivers – power demand and environmental upgrades — will be materially weaker going forward. First, while U.S. power demand expanded at a 1.5% compound annual rate from 1988 through 2007, it has declined at an 0.2% annual rate since, despite a 12% increase in real GDP over 2007-2016. Second, the entire generation fleet is now compliant with EPA limits on emissions of sulfur dioxide, nitrogen oxides, mercury, acid gases and particulate matter, significantly limiting the scope of future environmental capex. The withdrawal of the Clean Power Plan by the Trump Administration has eliminated the one remaining environmental regulation that might have accelerated gross additions of generation plant across large portions of the fleet. In this context, we believe generation capex in the long run is likely to slow materially from its recent rate and from the rate forecast by the public traded utilities for the next five years. The one bright spot is the potential for large investments in utility-owned renewable generation projects which, while unlikely to be sufficient to maintain the industry’s historical rate of growth in generation rate base, could help individual companies exceed the long run industry trend for a few more years.

The continued growth in transmission and distribution plant, by contrast, is less sensitive to power demand and to air emissions regulations. Even in an environment of stagnant demand growth, distribution networks must continue to expand in response to household formation. Transmission systems must not only accommodate customer growth, but also state renewable portfolio standards requiring the integration of new and often geographically isolated renewable resources. The power grid, moreover, is being upgraded through the deployment of smart grid technologies, such as customer meters capable of measuring electricity consumption by the minute and wirelessly communicating this data to the utility; devices that allow major pieces of equipment, such as transformers and substations, to be continuously monitored for signs of impending failure, allowing maintenance to be conducted on an as-needed basis as opposed to on a calendar schedule; and sensors, relays and switches that allow distribution circuits to which the supply of power has been interrupted to be supplied from alternative sources. Utilities on the Atlantic and Gulf coasts are also increasing capital expenditures on storm hardening of their transmission and distribution systems, including the deployment of concrete power poles and the undergrounding of distribution lines. We expect these and other network upgrades to continue in the years ahead as the grid integrates an increased amount of distributed generation, distributed storage and electric vehicles, whose charging requirements will require increased transformer capacity, upgraded distribution circuits, and two-way communication capability.

Over the next five years (2016-2021) our forecast of gross plant additions by segment relies on the disclosures made by the publicly traded U.S. utilities of their planned capital expenditures by segment.[6] To estimate the growth of net utility plant at each of these companies, we have calculated future depreciation expense on a segment basis, applying the rates of depreciation by segment used by each of these utilities in the preparation of its FERC Form 1 financial statements. By aggregating these granular, company-by-company forecasts we have estimated capex, depreciation and net utility plant by segment at the industry level over the next five years.

While we believe this to be the most reliable way to forecast company and industry growth in rate base over the medium term, we note that utilities’ medium-term capital expenditure plans are subject to rising uncertainty with time. Capex plans for the next 12 to 24 months tend to be relatively firm, as they correspond to projects that have already obtained the necessary regulatory approvals and construction permits and for which financing is in hand. Beyond this two year time horizon, capital expenditure plans are materially less certain. This is commonly reflected in a lower level of planned capital expenditures in the third, fourth and fifth years of company forecasts, with management tending to exclude from the forecast projects for which regulatory approvals and funding have not yet been obtained.

Because utilities tend not to disclose planned capital expenditures by segment beyond a five-year time horizon (currently, 2017-2021), the uncertainty around future capital expenditures increases markedly from 2022 on. Our estimates of segment capex for 2022 and beyond reflect the assumption that utilities’ capital expenditures will converge over 2022-2025 with our estimate of the long run, sustainable rate of capital expenditure by segment. Our annual estimates over this period, therefore, follow a glide path whereby each utility’s planned capital expenditures by segment capex in 2021 are gradually brought into alignment with our long-term estimates of sustainable growth.

Beginning in 2025, we assume that the capex plans of all the companies in the sector converge on the long-run, sustainable rate of investment by sector estimated on the basis of the historical data.

We have calculated these long run rates of investment for the generation, transmission and distribution segment, in the manner we describe below, and apply them to the corresponding portions of each utility’s rate base. The result is that our estimates of the long run growth rates of individual utilities can vary based upon the segment breakdown of their rate base.

We emphasize that numerous other factors could cause individual utilities’ growth rates to vary from our estimate of the normalized industry growth rate. Among the most important drivers of these differences will be variations in customer growth and in the growth in demand per customer, factors which would affect the level of investment required across all three industry segments. A second key set of drivers will be the age of existing plant by segment and the equipment replacement cycle of the utility. Older plant should be reflected in higher levels of maintenance and replacement capex, but utilities and their regulators can shorten or lengthen maintenance and replacement cycles depending on the relative priority placed on safety and reliability versus customer costs. Other factors that could cause companies to diverge from the industry average include states’ target levels of renewable generation, with utilities facing aggressive state renewable portfolio standards likely to spend more to build and integrate utility scale wind and solar power plants, as well as to add the generation resources required to provide frequency regulation and spinning reserves to offset the intermittent supply of renewable energy. The interaction of state environmental priorities and the characteristics of utilities’ generating fleets will drive differences in the pace of retirement of existing plants, whether to mitigate CO2 emissions, effluent discharge or the adverse environmental impact of once-through cooling water systems. Regional variations in the need to storm harden transmission and distribution circuits can drive material differences in capex. Over the longer term, the distribution systems upgrades required to integrate distributed generation and storage and, in particular, a growing fleet of electric vehicles could be distinguishing factors.

Our estimates of post-2025 growth by segment are best understood, therefore, as attempts to model a central tendency for the industry around which company performance will vary, but to which it may revert over time.

As a basis for estimating long-run sustainable growth by segment we have calculated the ratio of (i) gross plant additions to (ii) gross utility plant in each of the generation, transmission and distribution segments, both on an industry-wide and on a company by company basis, for each year from 1988 through 2016. In the transmission and distribution segments, our estimates of future gross plant additions are based upon the average ratio of gross plant additions to gross utility plant for the investor-owned, regulated utilities as a whole over the 1988-2016 period, calculated separately for the transmission and distribution segments. In the case of these two segments, our reliance of the average historical relationship between gross plant additions and gross utility plant reflects our view that the principal long term drivers of investment in these segments remain in place, including population growth and continued upgrades to enhance grid reliability, while others are gathering strength, including the integration of renewable resources, distributed generation, storage and electric vehicles.

To forecast growth in generation plant, however, we have adopted a more conservative approach. As noted above, we are skeptical that generation capex can be sustained at historical rates given the stagnation of power demand and the lack of opportunity to invest in environmental upgrades. We have therefore analyzed the historical data on generation plant additions so as to correct for the impact of the large generation capacity additions and environmental upgrades that we do not expect to continue. Our goal is to capture the organic pace of maintenance and replacement capex in generation, which we believe will drive the bulk of plant additions in the years ahead.

We have prepared two alternative forecasts, each based on a significantly more conservative methodology than that used for transmission and distribution. Having calculated for the electric utility industry the average ratio of gross generation plant additions to gross generation plant in each year over 1988-2016, we calculated the median of these ratios across 1988-2016. We chose to use the median rather than the average of the annual ratios because the scale and lumpiness of construction projects in this sector implies that gross additions of generation plant can be skewed materially higher by the completion of even a small number of large new power plants or emissions control projects. (Recall that upon completion of a power plant or emissions control project a large sum of capital is transferred from construction work in progress, where it may have of accumulated over a construction period of several years, to gross utility plant.) As a result, the annual average ratio of gross plant additions to gross utility plant can thus be materially above the median. Using the median ratio for each year allows to exclude the impact of large construction projects reaching completion and to capture more accurately, we believe, the organic pace of maintenance capex in the segment.

We also used a second, still more conservative method. Rather than calculate the median of the industry average ratio of gross plant additions to gross utility plant across 1988-2016, we instead (i) calculated the ratio of gross plant additions to gross utility plant by company, for each utility in the sector, for each year from 1998 through 2016, (ii) calculated the median of these company ratios in each year from 1988-2016, and (iii) calculated the median of those medians across 1988-2016. This approach further normalizes the data and produces a still lower forecast of generation plant additions.

Based on our estimates of the long-run, sustainable ratio of gross plant additions to gross utility plant for the transmission, distribution and generation segments, we have estimated for each regulated utility its annual additions of gross utility plant. We did this by multiplying each utility’s gross generation, transmission and distribution plant by our estimates the long-run sustainable ratio of gross plant additions to gross utility plant by segment. Netting out estimated depreciation by segment, we have estimated each utility’s net utility plant by segment. Aggregating these company estimates across the industry, we have developed estimates of aggregate additions of gross utility plant by segment and net utility plant in service by segment.

©2017, 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.

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  2. Our historical analysis of growth in the aggregate electric rate base of the U.S. utilities is based upon the FERC Form 1 filings of all the investor owned, regulated utility operating companies in the United States. By contrast, our forecast of growth in electric plant rate base for the five-year period from 2016 through 2021 relies on information provided by a sub-set of these companies, i.e., the capital expenditure forecasts disclosed by the publicly traded U.S. regulated electric utilities in their SEC filings and investor presentations. The aggregate electric rate base of the companies providing such capex forecasts is equivalent to approximately 80% of the aggregate electric rate base of the U.S. investor owned utilities as a whole. Our rate base growth forecasts are based upon these announced capex plans, the historical depreciation rates applied by each the utilities, and our estimates of the future trajectory of these companies’ deferred tax liabilities. We assumed the current tax policy continues for purposes of this analysis. Our estimates of depreciation and deferred taxes were prepared not only on a company by company basis but also by operating segment, taking into account (i) the rates of depreciation historically applied by each company to its generation, transmission and distribution plant, and (ii) the implications of tax incentives (including bonus depreciation, accelerated tax depreciation and the repair deductions) for the accumulation of deferred tax liabilities by segment. Longer term (2022-2025), our estimates of gross plant additions by segment are based upon the assumption that utility capex by segment will gradually revert to the industry’s long term historical trend. Please see the Appendix for a detailed explanation.
  3. Consider the completion delays and cost overruns experienced at the Edwardsport and Kemper County coal gasification projects and Vogtle and Summer nuclear plants.
  4. For 2011-2016, we have calculated the growth in the industry’s aggregate electric plant rate base using the FERC Form 1 filings of all U.S. investor-owned, regulated utility operating companies. Our rate base forecasts for 2021-2025 and for the long term are based upon SSR’s estimate of aggregate capital expenditures on electric utility plant offset by SSR’s estimate of depreciation and the growth in deferred tax liabilities. For 2016-2021, we have forecast rate base growth based upon the disclosed capital expenditures plans of the publicly traded, U.S. investor-owned regulated utilities. For the long term, we have prepared a range of rate base forecasts. The upper end of this range is predicated upon the assumption that (i) gross additions of transmission plant reflect the average over 1988-2016 of the ratio of gross plant additions to gross transmission plant in each year, (ii) gross additions of distribution plant likewise reflect the average over 1998-2016 of gross plant additions to gross distribution plant in each year, but (iii) gross additions of generation plant reflect the median over 1998-2016 of the ratio of gross plant additions to gross generation plant in each year. The lower end of the long-term forecast range is calculated in the same manner except that we assume that gross additions of generation plant reflect the median over 1998-2016 of the median in each year of the ratio of gross plant additions to gross generation plant at each of the regulated utility operating companies. Finally, for 2021-2025, we have assumed a glide path in the rate of growth of capital expenditures from the levels in managements’ forecasts to upper end of our forecast range for the long term.
  5. Utilities’ medium-term capital expenditure plans are subject to rising uncertainty with time. Capex plans for the next 12 to 24 months tend to be relatively firm, as they correspond to projects that have already obtained the necessary regulatory approvals and construction permits and for which financing is in hand. Beyond this two year time horizon, capital expenditure plans are materially less certain. This is commonly reflected in a lower level of planned capital expenditures in the third, fourth and fifth years of company forecasts, with management tending to exclude from the forecast projects for which regulatory approvals and funding have not yet been obtained.
  6. The aggregate electric rate base of the companies providing such capex forecasts is equivalent to approximately 80% of the aggregate electric rate base of the U.S. investor owned utilities as a whole.
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