What Is the Floor for Rate Base Growth? And Which Utilities Face the Greatest Challenge to Sustain Their Current Growth?

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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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November 21 , 2017

What Is the Floor for Rate Base Growth?

And Which Utilities Face the Greatest Challenge to Sustain Their Current Growth?

In this note we estimate the floor on electric rate base growth supported by the need to maintain existing plant and to connect and supply new customers (referred to hereafter as “maintenance capex”). We estimate that, across the universe of U.S. publicly traded regulated utilities, maintenance capex, alone, is sufficient to drive growth in aggregate electric rate base of only 2.3% p.a. By contrast, over 2016-2021, the disclosed capital expenditure plans of these same companies would, by our estimate, drive growth in aggregate electric rate base of 6.5% p.a., broadly in line with the pace of growth realized over the last decade (6.7% p.a. over 2006-2016). To sustain rate base growth at current levels, therefore, utilities must find significant new opportunities for growth capex, even as the demand for electricity remains broadly unchanged from ten years ago.

We have repeated this analysis for each of the publicly traded regulated utilities, measuring the gap between the capital expenditures currently forecast by management over the next five years and the level that can be sustained by maintenance capex alone. The companies where this capex gap is largest should face the greatest challenge in sustaining capex and rate base growth at levels commensurate with management’s guidance for next five years, while those where the gap is smallest will have the easiest path to deliver long term rate base growth in line with current expectations. We find that, with the single exception of NWE, maintenance capex falls far short of current capex plans and is insufficient to sustain the current pace of rate base growth. POR, CMS, ALE and LNT among the primarily regulated utilities, and NEE and PEG among the hybrids, will likely face the biggest challenge in sustaining long term rate base growth at the pace forecast for the next five years. ES, CNP, ED and HE would face the smallest capex deficit (see Exhibits 1 and 11.) At all of these companies, the capex shortfall is material, and would require the identification of significant new growth capex opportunities to offset it.

Finally, we are updating our assessment of the most and least attractive electric utilities (see final bullet on page 2).

Portfolio Manager’s Summary

  • Among regulated utilities, growth in the equity component of rate base, as measured by net book value, is a key long-term driver of total shareholder returns, explaining 54% of the total industry return and 26% of the total shareholder return for individual utilities since 1995 (Exhibits 3 and 4). Estimating long run rate base growth has therefore been a central focus of our recent research, including this note.
  • Based upon the disclosed capital expenditures plans of the publicly traded U.S. regulated utilities, we expect the sector to realize 6.5% average annual growth in aggregate electric rate base over the five years 2016-2021, broadly in line with the 6.7% CAGR realized over the last decade.
  • The level of capital expenditures required to achieve these rates of growth, however, is well above the industry’s long-term mean, as reflected in the average ratio of gross plant additions to gross plant in service over 1988-2016. A reversion to historical average rates of capex by segment would be consistent with growth in aggregate electric rate base of just 5.1% p.a.
  • We view the floor on utility capex as the level required simply to maintain existing plant, and connect and supply new customers (“maintenance capex”). Maintenance capex, we estimate, supports growth in aggregate electric rate base of only 2.3% p.a.
  • We have compared our estimates of maintenance capex by company to the capex levels currently forecast by these companies’ managements over the next five years. Utilities where this gap is largest face the greatest challenge in sustaining capex levels commensurate with management’s current guidance. By contrast, those utilities where the gap is smallest will require fewer additional capex opportunities to maintain growth at a rate consistent with current expectations.
  • We find that, with the single exception of NWE, maintenance capex falls far short of current capex plans and is insufficient to sustain the current pace of rate base growth. The primarily regulated utilities that face the largest capex gap are POR, CMS, ALE and LNT; at these companies, maintenance capex would support growth in electric rate base that is 84% to 190% below our growth estimates for the next five years. (See Exhibits 1 and 11).
  • ES, CNP, ED and HE would likely see rate base growth fall the least if their capital expenditures were limited to maintenance capex alone; even at these companies, however, the deceleration would be significant, with maintenance capex supporting rate base growth at levels 15% to 34% lower than that expected over the next five years.
  • Among the hybrid utilities, NEE and PEG would require the largest amount of new growth capex to sustain their current rate base growth; at these two companies, maintenance capex supports growth in electric rate base that is 81% to 86% below that expected over the next five years. The smallest capex deficits would be at EXC and FE, but even here maintenance capex supports rate base growth that is 55% below current forecasts.

Exhibit 1: Percentage Difference Between Rate Base Growth Supported by Maintenance Capex Alone, vs. the Rate Base Growth Supported by Managements’ Announced Capex Plans over 2017-21

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

  • We are updating our assessment of the most and least attractive electric utilities to reflect the results of our recent research on long-term rate base growth potential, including this note; recent changes in state and federal regulatory policies; as well as movements in market valuations.
  • We are removing XEL from our list of most attractive regulated electric utilities, reflecting the increase in its stock price since adding it to our most preferred list in May.
  • We are removing SCG from our list of least attractive regulated electric utilities, reflecting the drop in its price since adding it to our list of least preferred utilities in May.
  • We are adding EXC and FE to our list of most preferred hybrid utilities.
  • We are adding POR and SO to our list of least preferred regulated electric utilities.
  • We are removing JASO from our list of least preferred renewables companies, reflecting the deal to take it private by its founder.

Exhibit 2: Heat Map: Our Preferences Among Utilities, IPPs and Clean Technology Stocks

Source: SSR analysis

Details

This note is the fourth and last in a series examining the drivers of and outlook for rate base growth across the U.S. regulated electric utilities. In the first of these, Rising Growth and Falling Beta: Electric Utility Rate Bases Show Accelerating Growth Through 2021, we estimated the likely pace of rate base growth for each of the publicly traded electric utilities over the next five years, based on the capital expenditure plans disclosed by the managements of these companies in their SEC filings and investor presentations.[1] The second note in the series, 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?, explored the implications for the industry and individual utilities of capital expenditures decelerating in future to a long run pace of growth closer to the industry’s historical mean.[2] The third note, Antiquated Power Grids: What Can Age of Plant Tell Us About Future Rate Base Growth?, analyzed the relative age of the transmission and distribution grids of each utility and what that might mean for future capex plans.[3] In this note, we estimate the floor on electric rate base growth supported solely by the need to maintain existing plant and to connect and supply new customers (hereafter referred to as “maintenance capex”).

Growth in rate base is the single most important driver of long run earnings growth and thus total shareholder return among regulated electric utilities.[4]Since 1995, a regression analysis of (i) the five year total shareholder return on the publicly traded, regulated electric utilities as a group vs. (ii) the five year CAGR in the equity component of these utilities’ aggregate rate base, as estimated by net book value per share,[5] results in an r-squared of 0.53, suggesting that rate base growth explains approximately half of total shareholder return in the medium term (see Exhibit 3). At the individual utility level, the relationship between rate base growth and total shareholder return is weaker, but still material. As illustrated in Exhibit 4, a regression analysis of (i) the five-year total shareholder return on the shares of the publicly traded, regulated electric utilities individually vs. (ii) the five year CAGR in the equity component of each utility’s aggregate rate base, as estimated by net book value per share, results in an r-squared of 0.26, suggesting that rate base growth explains approximately a quarter of total shareholder return at the company level.

The fact that the r-squared in these regressions is higher for the industry than for individual companies suggests to us that growth in earnings and total shareholder returns may temporarily diverge from rate base growth at the company level in response to other factors, such as a utility’s success in securing revenue increases to reflect the rise in its electric rate base; changes in the allowed return on equity set by the utility’s by regulators; and a utility’s success or failure in realizing that allowed return through the control of operating and financial expenses. Across the industry, some of these company-specific factors seem to cancel each other out.

In choosing among regulated utilities, investors particularly value management forecasts of rate base growth not only because of the visibility they provide into the long-term growth of earnings but also because the other earnings drivers listed above are much more difficult to predict. Aware of this, utility management teams compete to offer compelling forecasts of future rate base growth. Our concern is that investors may lose sight of the fact that the current pace of rate base growth materially exceeds the long term historical average, and that the pace of capex required to sustain current rate base growth far exceeds what may be expected in a sector where power demand has ceased to grow. Utilities faced with the highest level of maintenance capex requirements will thus have an advantage in sustaining their current level of rate base growth, while the success in finding incremental growth capex opportunities above maintenance capex will likely be one of the key differentiators between utilities as we move into the next decade.

Exhibit 3: Five Year Total Shareholder Return on U.S. Regulated Electric Utility Stocks as a Group vs. Five Year CAGR in Net Book Value per Share, 1995-2016

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Source: FERC Form 1, SNL, SSR analysis

Exhibit 4: Five Year Total Shareholder Return on U.S. Regulated Electric Utility Stocks Individually vs. Five Year CAGR in Net Book Value per Share, 1995-2016

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Source: FERC Form 1, SNL, SSR analysis

The Current Outlook for Rate Base Growth – and the Challenge to Sustain It

Based upon an analysis of U.S. regulated utilities’ announced capex plans, depreciation rates and prospective deferred tax liabilities, we forecast ~6.5% compound annual growth in the industry’s aggregate electric plant rate base over 2017-2021 (see Exhibit 5). While this forecast rate of growth is broadly in line with the 6.7% compound annual growth in aggregate electric rate base over the last decade (2006-2016), we note that over the last three decades growth in electric plant rate base has averaged only 3.8% p.a. (see Exhibit 6).

Exhibit 5: Historical and Estimated Growth of the Aggregate Electric Plant Rate Base of U.S. Investor Owned Utilities (2007-2021E) (1)

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1. 2017-2021 growth estimates reflect the announced capital expenditure plans of the publicly traded investor owned utilities in the U.S. that have provided such forecasts 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.

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

In our research report of October 2nd, If This Is the Golden Age of Electric Utilities, What’s Next?[6]we examined the average rate of electric plant additions over this longer historical period. More precisely, we analyzed the average ratio over 1988-2016 of (i) gross additions of electric utility plant to (ii) gross plant in service, for the generation, transmission and distribution segments individually. We then assessed the implications for future rate base growth of a reversion to the historical mean in utilities’ pace of plant additions. To do so, we estimated a baseline for the long run trend of electric rate base growth based upon (i) utilities’ average pace of capital expenditure in the generation, transmission and distribution segments over 1988-2016; (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 also took into account secular changes that may speed or slow capex and rate base growth in future, such as the stagnation of U.S. power demand over the last decade and the scheduled phase-out of bonus depreciation by 2020. Our analysis suggests that a reversion to the historical mean in the pace of additions of utility plant would be consistent with a slowdown in electric rate base growth to ~5.1% p.a., well below the 6.5% annual pace estimated for the next five years (see Exhibit 7). A summary of this analysis is set out in Appendix 1 to this note.

Exhibit 6: Electric Plant Rate Base of U.S. Investor Owned Utilities ($ Billions) (1)

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1. Includes construction work in progress (CWIP)

Source:  FERC Form 1, SNL, SSR analysis

Exhibit 7: Comparison of Historical Growth in Electric Rate Base over 2011-2016; Expected Growth in Electric Rate Base over 2016-2021, Based Upon Managements’ Disclosed Capex Plans; Future Rate Base Growth Sustainable at the Industry’s Average Capex Rates of 1988-2016; and Future Rate Base Growth Sustainable by Maintenance Capex Alone

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

In this note we take a different approach, estimating the floor on rate base growth supported solely by the need to maintain existing electric utility plant, as well as to connect and supply new customers (referred to hereafter as “maintenance capex”). As explained below, we estimate that maintenance capex would drive growth in aggregate electric plant rate base of only 2.3% p.a. (Exhibit 7). To maintain rate base growth near the 6.5% level consistent with current investment plans, therefore, utility management teams must find significant new capex opportunities to sustain a pace of investment well above that required by maintenance capex alone.

In Exhibit 8, we set out the rate of capital investment (more precisely, the annual ratio of gross additions of electric utility plant to gross electric plant in service) assumed in each of the three above estimates of rate base growth. First, our estimate of 6.5% annual growth in aggregate electric rate base over the next five years assumes a ratio of gross plant additions to gross plant in service of 9.4% p.a. in the transmission segment, 7.7% p.a. in the distribution segment and 5.2% p.a. in the generation segment, ratios that in turn reflect the announced capex plans of the publicly traded electric utilities. Second, in a scenario where utility capex returns to its long run historical average over 1988-2016, the ratio of gross plant additions to gross plant in service would fall to 6.4% p.a. in the transmission segment, 6.2% p.a. in distribution and 4.5% in generation; this lower rate of investment, we estimate, would drive rate base growth of only 5.1% p.a. Third, we estimated the rate of maintenance capex required to maintain existing electric utility plant, as well as to connect and supply new customers. The corresponding capex ratios, assuming no additional growth capex, are 3.1% for the transmission segment, 5.3% for the distribution segment and 2.5% for the generation segment. These ratios are consistent, by our calculation, with rate base growth of only 2.3% p.a. (A detailed explanation of our methodology for estimating maintenance capex is presented in Appendix 2 and reflects the results of our analysis of age of plant in our note from October 25, Antiquated Power Grids: What Can Age of Plant Tell Us About Future Rate Base Growth?.[7] In general terms, the older the plant in service, and the more rapid the pace of customer growth, the higher the required level of maintenance capex.)

Exhibit 8: Ratios of Gross Plant Additions to Gross Plant in Service Implied by Utilities’ Announced Capex Plans over 2017-2021, the Electric Utility Industry’s Historical Average Capex over 1988-2016, and Our Estimates of Maintenance Capex

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

Exhibit 8 above illustrates the fact that declines in the ratio of plant additions to existing plant can have a greater than proportional impact on rate base growth. For rate base to grow, gross plant additions must exceed depreciation and the build-up of deferred tax liabilities, which are offset against plant in service in the calculation of rate base. Once this hurdle has been met, incremental additions to gross utility plant can materially accelerate rate base growth. Just as firms with high fixed costs will see earnings grow more rapidly than revenues, so utilities can see rate base grow at a pace that exceeds plant additions.

The Impact on Individual Utilities of a Decrease in Capex to Maintenance Levels

The final step of our analysis was to compare at each utility (i) the capex levels currently forecast by the company’s management over the next five years with (ii) the far more limited capital expenditures required solely to maintain existing utility plant and connect and supply new customers. We found that, with the single exception of NWE, maintenance capex falls far short of current capex plans and is insufficient to sustain the current pace of rate base growth. The companies where this gap is largest face the greatest challenge in sustaining capex in the long term at levels commensurate with management’s guidance for next five years. Those where the gap is smallest face the easiest path to deliver long term rate base growth in line with current expectations.

Our analysis suggests that, with exception of NWE, all regulated electric utilities would experience materially slower rate base growth if limited to maintenance capex alone. The primarily regulated utilities that will face the largest gap relative to current rate base growth are, by our estimate, POR, CMS, ALE and LNT; at these companies, maintenance capex sustains growth in electric rate base that is 84% to 190% below our growth estimates for the next five years. (See Exhibits 9 and 11).

At the other end of spectrum, we estimate that maintenance capex at ES, CNP, ED and HE is closest to the levels required to sustain rate base growth at the pace of expected for these companies over the next five years. Even at these companies, however, the deceleration in rate base growth if no additional capex opportunities were found would be significant, with rate base growth estimated to fall by 15% to 34% relative to that expected over the next five years. (See Exhibits 9 and 11).

Among the hybrid utilities, NEE and PEG would have to find the largest amount of additional capital expenditure opportunities to sustain current rate base growth; at these two companies, maintenance capex alone would drive growth in electric rate base that is 81% to 86% below that expected over the next five years. Least challenged among the hybrids, we estimate, would be EXC and FE, but even here, in the absence of new growth capex, maintenance capex alone provides a floor to rate base growth that is 55% below current forecasts.

Exhibit 9: Percentage Difference Between Rate Base Growth Supported by Maintenance Capex Alone, vs. the Rate Base Growth Supported by Managements’ Announced Capex Plans over 2017-21[8]

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

Exhibit 10: Percentage Point Difference Between the Rate Base Growth Supported by Maintenance Capex Alone, vs. the Rate Base Growth Supported by Managements’ Announced Capex Plans over 2017-21 9

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

Exhibit 11: Comparison by Company of Historical Rate Base Growth, Expected Rate Base Growth Over 2016-2021 Based Upon Managements’ Disclosed Capex Plans, and the Pace of Rate Base Growth Sustainable by Maintenance Capex Alone

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

How Capex at Maintenance Levels Would Affect the Composition of Utility Investment

Over the last decade, the annual consumption of electricity in the United States has remained broadly unchanged, as the growth in the number of customers has been offset by efficiency gains that have reduced electricity usage per customer. If this trend continues, and we expect it will, we will see little pressure to add new generation and high voltage transmission capacity to serve growth in power demand. On the other hand, customer growth continues to imply the need for new connections to these customers’ premises, and thus a need for ongoing investment in the distribution grid.

Exhibit 12: Three Year CAGR (2013-2016) in Customer Growth by Utility

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

Our methodology for estimating maintenance capex by segment is set out in detail in Appendix 2, and reflects the results of our analysis of age of plant in our note from October 25, Antiquated Power Grids: What Can Age of Plant Tell Us About Future Rate Base Growth?.[9] In the absence of growth in power demand, our estimates of maintenance capex in the generation and transmission segments seek to exclude new capacity additions, and to capture only those capital expenditures required to maintain existing plant. In general terms, the older a utility’s generation and transmission plant in service, the higher the required level of maintenance capex.

In the distribution segment, by contrast, we have sought to capture those capital expenditures required not only to maintain existing electric utility plant, but also to connect and supply new customers. To estimate maintenance capex in the distribution segment, therefore, we have extrapolated into the future each utility’s compound annual rate of customer growth over the last three years (see Exhibit 12). (Customer growth slowed meaningfully in the years following the Great Recession in 2008, but showed a material and sustained increase across almost all utilities

since 2013). We then multiplied the expected growth rate in the utility’s customers by the ratio of the replacement cost of the utility’s distribution plant in service to its gross book value. The underlying concept is that the physical assets required to connect each new customer to the utility’s grid are broadly similar today to what they have been historically; to deploy these assets today, however, will cost more than the historical book value of similar assets on the utility’s system.

Aggregated across the industry, our estimates of utilities’ maintenance capex requirements are equivalent to only 50% of utilities’ announced capex plans over 2017-2021. In addition, given a scenario where utilities’ capital expenditures were limited to maintenance capex alone, we would expect a material shift in the composition of utilities’ capital expenditures, reflecting our assumptions of continued customer growth in the context of stagnant overall power demand.

In summary, when aggregated across the industry, utilities’ announced capex plans over 2017-2021 would allocate some $91 billion to generation capex; by contrast, in the absence of growth in power demand, we estimate that utilities require only $42 billion to maintain their existing generating fleets. Similarly, utilities plan to spend $95 billion on transmission capex over 2017-2021; by contrast, we estimate that capex of only $27 billion is required to maintain these utilities’ transmission assets. Faced with a continued need to connect and supply new customers, however, we would expect a smaller decline in distribution capex, from the $158 billion currently planned by utilities over 2017-2021 to $103 billion in a scenario where capital expenditures are limited to maintenance capex alone (see Exhibit 13). The corresponding percentage declines in capex by segment would be 54% in generation and 72% in transmission, but only 35% in distribution (see Exhibit 14).

Exhibit 13: Estimated Maintenance Capex by Segment Compared to Utilities’ Announced Capex Plans over 2017-2021 ($ Billions)

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

Exhibit 14: The Capex Gap: Percentage Shortfall of Estimated Maintenance Capex by Segment Compared to Utilities’ Announced Capex Plans over 2017-2021 (%)

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

In a scenario where utilities’ capital expenditures were limited to maintenance capex alone, therefore, we would expect distribution’s share of total maintenance capex to rise to ~60%, as compared to 46% of utilities’ planned capital expenditures over 2017-2021 (see Exhibit 15). Transmission capex, by contrast, would fall from 28% of the total over the next five years to an estimated 16% of maintenance capex. The share of generation capex, we estimate, would remain broadly unchanged. The greater weight of distribution in a maintenance capex scenario reflects not only the need to continue to connect new customers, but also the shorter useful life of distribution assets: even in the absence of customer growth, we estimate the required ratio of gross plant additions to gross plant in service in the distribution segment to be 4.3% p.a., materially higher than the corresponding capex ratios for the generation and transmission segments (3.1% and 2.5%, respectively).

Exhibit 15: Breakdown of the Electric Utility Industry Capex by Segment

Managements’ Announced Capex Plans over 2017-2021 Estimated Replacement and Maintenance Capex

 

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

In a scenario where utilities’ capital expenditures were limited to maintenance capex alone, therefore, utilities with the highest proportion of distribution capex in their current capex plans (e.g., EXC) would likely find it easier to minimize the decline in their capital expenditures– particularly if they are experiencing rapid rates of customer growth (e.g. CNP, NWE, PNW). Utilities whose current capex plans are heavily skewed towards transmission, by contrast, face larger potential shortfalls in their capex budgets. In Exhibit 16 we provide a breakdown of the regulated electric utilities’ planned capital expenditures by segment over 2016-2021.

Exhibit 16: Breakdown of the Regulated Electric Utilities’ Expected Rate Base Growth

by Segment Over 2016-2021, Based Upon Utilities’ Disclosed Capex Plans

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

Exhibit 17 estimates for each of the publicly traded utilities the percentage difference between the level of capital expenditures planned by management over 2017-2021 and the level required if capital expenditures were limited to maintenance capex alone. Of the companies facing the largest capex gap, and therefore having the largest need for new capex opportunities, a few can take solace in the age of their existing transmission and distribution plant. In our note of October 25, Antiquated Power Grids: What Can Age of Plant Tell Us About Future Rate Base Growth?,[10] we identified CMS, LNT and PEG as having some of the oldest transmission and distribution plant in service, based on the percentage of their customers that were added before 1967 and after 1988. The age of their transmission and distribution assets may offer these companies potential capex opportunities in replacing aging T&D equipment that remains in service in support of greater grid reliability.

Exhibit 17: The Capex Gap by Utility: Percentage Shortfall of Estimated Maintenance Capex Compared to Utilities’ Announced Capex Plans over 2017-2021 (%)

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

Ratings Changes

Additions to List of Most Preferred Hybrid Utilities

Exelon (EXC): We had previously included EXC on our list of most preferred utilities due to its rapid regulated electric rate base growth and discounted valuation, but removed it due to the risks in the power markets. The benefits from recent policy changes, including zero emissions credits (ZECs) and the likely changes in price formation rules in PJM, will support earnings and cash flows from EXC’s competitive generation fleet. In addition, EXC will benefit from tax reform, both in its competitive segment and its regulated operations, where the reduction in the corporate tax rate will quickly reduce the under earning at the utilities acquired in the Pepco acquisition.

FirstEnergy (FE): FE’s earnings and valuation have been eroded by the poor performance of its competitive generation business. The impending bankruptcy of FE’s competitive generation subsidiary (FES), and concerns about FE’s ability to protect itself against the claims of FES’ creditors, have caused FE to trade at a significant valuation discount versus the primarily regulated utilities as well as other hybrid utilities. By contrast, we believe there will be limited financial impact on FE from an FES bankruptcy and that the remaining, purely regulated company is trading at a 20% discount to other regulated electric utilities. Furthermore, our age of plant and long-term rate base growth analysis suggests that FE may have opportunities to accelerate its current pace of rate base growth, and to grow faster than the industry average well into the next decade.

Additions to List of Least Preferred Regulated Electric Utilities

Portland General Electric (POR): Even after POR’s recent capex guidance increase, rate base and earnings growth at POR should be well below the industry average over the next five years, and we see limited opportunity for POR to accelerate its growth meaningfully thereafter. While POR has the possibility to add new generation in its integrated resource plan, even a 50% increase in its capex plans will not bring its growth out of the bottom quintile among its regulated utility peers. In part, this reflects POR’s election not to take bonus depreciation, which implies that it will not benefit from the accelerated roll-off of deferred taxes over the next decade or more. Nevertheless, POR trades at a premium to the industry despite below average earnings growth for the next several years. Although this premium is partly due to its potential as an acquisition target, we believe there are other, similar sized utilities with either better growth opportunities, a lower valuation or both, that would likely be acquired first.

Southern (SO): Southern has underperformed over the past year due to its issues with the Kemper IGCC in Mississippi and the new nuclear plants at Vogtle in Georgia. Our rate base growth research suggests that SO’s below average rate base growth will continue into the future, reflecting low normalized rates of capital expenditure and a younger than average T&D network. We therefore expect SO to continue to underperform for the next several years, due to disappointing growth opportunities and risks from Vogtle, as well as the additional risk of acquisitions as SO tries to find other means to sustain its growth.

Removal from List of Most Preferred Regulated Electric Utilities

Xcel Energy (XEL): We upgraded XEL on the expectation that the company’s cost management efforts would deliver earnings growth not anticipated in consensus estimates. Since our upgrade, however, consensus earnings estimates have increased to reflect most of these opportunities and are now closer to our estimates. Moreover, XEL’s outperformance since we added them to our most preferred list has brought its valuation into line with our earnings expectations. Finally, our analysis of age of plant and long-term rate basis growth suggest that it could be challenging for XEL to maintain its growth rate into the next decade. While we do not expect XEL to underperform versus the sector, and there is still some potential upside from approvals of additional wind projects, we now see limited room for outperformance.

Removal from List of Most Preferred Regulated Electric Utilities

SCANA (SCG): Since we added SCG to our list of least preferred electric utilities in May due to our concerns about the VC Summer nuclear project, SCG has abandoned the plant, multiple concerns have arisen about how the project was run, and the stock price has declined by over a third. While there is still the risk of a complete write-off of the project and roll-back of prior rate increases that could result in additional downside of 25-30%, we believe this is unlikely. We believe the most likely scenarios, involving additional write-offs and some form of recovery of the remaining investment without return, allow additional upside, although the most recent offer by SCG caps the upside to 20-25%. Therefore, although the risk of a large drop of 25% or more is limited from here, the upside is also limited, preventing us from supporting an investment in SCG at this time.

Appendix 1: If Utility Capital Expenditures Revert to Their Historical Mean, What Pace of Rate Base Growth Could the Sector Sustain?

In this Appendix, we estimate the rate of growth in aggregate electric rate base assuming that utility capital expenditures revert to their historical mean. 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.

Utility Plant Additions

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 18, 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 axis, tracks net generation plant in service over time.

Exhibit 18: 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 18 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 19 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 18 and 19). 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 19: 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 20).  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 20: 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

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 21.

Exhibit 21: 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 21).

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 22). 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 23, 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 23). The net impact of deferred taxes on rate base, illustrated by the green columns in Exhibit 23, 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 22: Bonus Depreciation Rates by Year

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Source: Internal Revenue Service

Exhibit 23: Estimated Annual Change in Aggregate Rate Base of U.S. Regulated Electric Utilities Attributable to Changes in Deferred Taxes

________________________

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.

Appendix 2: Estimating Maintenance Capex

We have relied on a series of assumptions and estimates to forecast the level of capital expenditure consistent with maintaining existing electric plant, and connecting and supplying new electricity customers (“maintenance capex”). The key assumptions and estimates underpinning our calculations are explained below.

For transmission and distribution plant, a critical initial step was to estimate the replacement cost of gross plant in service on a company-by-company basis. We did this by adjusting the book value of transmission and distribution gross plant in service to reflect the current price level. Having done so, we applied each utility’s depreciation rate by segment to the inflation adjusted value of its segment assets, thereby estimating an inflation-adjusted value for depreciation expense. We have assumed that in the transmission and distribution segments, the capex required to maintain existing plant is roughly equivalent to the inflation adjusted value of segment depreciation.

Calculating an inflation-adjusted value for transmission and distribution gross plant in service involved three steps. The first of these was to multiply the dollar value of gross plant additions in each historical year, as reported by utilities in their FERC Form 1 filings, by the ratio of the producer price index in 2017 to that prevailing in the year of the plant addition. To make this adjustment as accurate as possible we used the average of the transformer and power wire and cable sub-components of the producer price index.

Unfortunately, FERC Form 1 data on gross plant additions are available in electronic form only back to 1988. Lacking electronic data on gross plant additions prior to that year, our second step was to estimate the replacement cost of the gross plant in service on utilities’ balance sheets in 1988. To do so, we assumed that these assets had been placed in service, on average, ten years earlier. To arrive at the replacement cost of these assets, therefore, we multiplied 1988 gross utility plant in service by the ratio of the 2017 price level to that prevailing in 1978.

Having summed these estimates of transmission and distribution gross utility plant placed in service, the third step was to adjust them to take into account retirements of transmission and distribution plant since 1988. For accounting purposes, the estimated useful life of transmission and distribution plant generally ranges from 30 to 40 years; in practice, the useful life of these utility assets can be even longer. We therefore assumed that any transmission and distribution assets retired since 1988 must have been placed in service prior to 1988. As noted above, we assumed that all plant in service in 1988 had been placed in service, on average, 10 years earlier. To account for retirements, therefore, we multiplied (i) each utility’s historical retirements of gross utility plant over the last three decades by (ii) the ratio of the 2017 price level, as measured by the producer price index, to that prevailing in 1978. Subtracting inflation adjusted retirements from inflation adjusted plant in service in 1988, and adding inflation adjusted additions of utility plant since 1988, we were able to estimate the inflation adjusted value of transmission and distribution gross plant in service today.

We did not apply the methodology described above to generation plant in service out of concern that by doing so we might materially over-estimate the replacement cost of generation plant. Our concern reflects the fact that the real cost of new generation capacity has fallen dramatically over the last 30 years, as the nation’s utilities have shifted away from high capital cost coal fired, nuclear and hydroelectric generating assets towards low capital cost gas turbine and combined cycle gas turbine generators. Given this shift in technology choice, a simple inflation adjustment of gross generation plant in service would materially over-estimate the cost of replacing the existing generating fleet.

Today, approximately a quarter of U.S. power generation capacity is coal fired; another 9% is nuclear; a further 9% comprises conventional large-scale hydro or pumped storage facilities; and a further 3% is oil fired. Most of these generating assets, which together comprise almost half of U.S. generation capacity, entered service over 30 years ago. Adjusted for inflation, the capital cost of these assets can be estimated to be at least $3,000 to $4,000 per kW installed. Over the last 20 years, however, additions of hydroelectric, nuclear, coal and oil-fired capacity have been rare; rather, the overwhelming majority of capacity additions over this period have been gas fired. The cost of new combined cycle gas turbine generator can be estimated at $1,000 per kW, and that of a simple cycle gas turbine at $700/kW. In recent years, the scale of wind and solar generating capacity additions have begun to rival those of gas fired generation capacity. While the capital cost of these renewable energy plants exceeds that of gas fired capacity, it can be estimated conservatively at $1,500 to $2,000/kW and thus is still well below the cost of existing coal, nuclear and hydroelectric capacity. Given this secular decline in the cost of new generation capacity, we decided against estimating the cost of replacing existing generation plant by using the inflation adjusted cost of existing plant in service. A second consideration guiding us to this decision is the fact that maintenance capex for gas fired and renewable generation capacity is a fraction of that required by coal nuclear and oil power plants. With gas fired and renewable generation capacity now accounting for approximately half of U.S. installed capacity, the cost of maintenance as well as replacement capex has declined materially.

We therefore adopted an alternative approach to estimating the rate of capital expenditure on generation, taking as our benchmark a historical period (1988-2000) when the growth of generation capacity was comparable to what we would expect today. Over the last ten years, utility scale generation capacity in the U.S. has expanded at ~0.85% p.a., down from a rate of ~2.43% p.a. over the prior ten years. Over the last three decades, the historical period most comparable to 2006-2016 were the years from 1988 through 2000, when U.S. generation capacity was expanding at an average annual rate of ~1.5%. To estimate the ratio of gross additions of generation plant in future years, therefore, we first analyzed the performance of this ratio over 1988-2000.

We conducted our analysis at the utility level, measuring the ratio of gross plant additions to gross generation plant in service at each of the regulated utilities over this period. We found that in 80% of the cases the ratio was at 4% or below; the remaining 20% of the cases, when the ratio was materially higher, appear to reflect the impact of substantial additions of new generation capacity. To estimate the rate of investment in generation plant in the absence of such capacity additions, we averaged those observations where the ratio was at 4% or below.

We then calculated the average ratio of gross plant additions to generation plant in service across the regulated utilities over the last ten years (2006-2016), when the pace of capacity additions was materially faster but utilities’ choice of generation technology was broadly similar to what we would expect today (i.e., concentrated on gas fired and renewable generation technologies). Excluding those instances when the ratio of gross additions of generation plant to gross plant in service exceeded 4%, and thus was likely associated with significant new capacity additions, we found that the ratio of gross capacity additions to gross plant in service averaged 2.5% in the remaining instances. We have used this average ratio of 2.5% to estimate maintenance capex in the generation segment in a period when the industry does not require net additions of generation capacity.

The final element of our estimate of maintenance capex was the rate of investment in the distribution segment required to connect new customers. We estimated these capital expenditures by extrapolating into the future each utility’s compound annual rate of customer growth over the last three years (customer growth slowed meaningfully in the years following the Great Recession in 2008, but showed a meaningful and sustained increase across almost all utilities since 2013). We then multiplied the expected growth rate in the utility’s customers by the ratio of the replacement cost of the utility’s distribution plant in service to its gross book value. (We calculated this ratio by applying the inflation adjustment methodology described on the preceding page.) The underlying concept is that the physical assets required to connect each new customer to the utility’s grid are broadly similar today to what they have been historically; to deploy these assets today, however, will cost more than the historical book value of similar assets on the utility’s system. To capture accurately the incremental capital cost of each new customer, therefore, it is necessary to adjust the book value of the utility’s distribution assets to reflect their cost today.

©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.

  1. http://www.ssrllc.com/publication/rising-growth-and-falling-beta-electric-utility-rate-bases-show-accelerating-growth-through-2021/ 
  2. http://www.ssrllc.com/publication/if-this-is-the-golden-age-of-electric-utilities-whats-next-or-how-fast-can-rate-base-grow-in-the-long-term-and-on-what-will-utilities-spend/ 
  3. http://www.ssrllc.com/publication/antiquated-power-grids-what-can-age-of-plant-tell-us-about-future-rate-base-growth/ 
  4. Rate-regulated utilities are allowed to recover their prudently incurred cost of service in rates, including all costs to procure fuel and purchased power, operation and maintenance expense, depreciation expense, income and other taxes, and a fair return on rate base. Rate base represents the capital invested by a rate-regulated utility monopoly in the supply of a public service (e.g., electricity or gas) and is roughly equivalent to the net depreciated historical value of the utility’s plant, property and equipment. Rate base may be funded by common and preferred equity, long term debt and net deferred tax liabilities. On the debt portion of rate base, utilities are generally allowed to earn a return equivalent to their embedded cost of long term debt. A similar approach is to taken the recovery of the cost of preferred equity. Because a utility’s deferred tax liability largely represents income taxes expensed but not yet paid, and thus does not represent an outlay of capital, regulated utilities are not allowed to earn a return on deferred taxes. As a result, rate base is generally calculated as the net depreciated historical cost of a utility’s property, plant and equipment net of the utility’s deferred tax liability. Finally, on the portion of rate base funded with equity (a proportion set by regulators at a level deemed adequate to sustain an investment grade rating on the utility’s long-term debt, and referred to as the “equity ratio”) utilities are allowed to earn a fair return (the utility’s “allowed ROE”) as determined by regulators in periodic rate cases. Given this regulatory framework, it is common for investors to estimate future utility earnings as the product of rate base, the utility’s equity ratio and its allowed ROE. 
  5. Since the group of companies derived greater the 75% of their earnings, and in most cases 90% or more, from regulated utility operations, the growth in net book value should approximate the growth in the underlying equity component of rate base. 
  6. http://www.ssrllc.com/publication/if-this-is-the-golden-age-of-electric-utilities-whats-next-or-how-fast-can-rate-base-grow-in-the-long-term-and-on-what-will-utilities-spend/ 
  7. http://www.ssrllc.com/publication/antiquated-power-grids-what-can-age-of-plant-tell-us-about-future-rate-base-growth/ 
  8. SCANA’s expected rate base growth over 2016-21 is distorted by a $2.2 billion increase in deferred taxes resulting from the write-off of its investment in the V.C. Summer nuclear power plant. The scale of this increase in deferred taxes causes SCANA’s growth in electric rate base to be negative over the next five years. A scenario where capital expenditures are limited to those required for the maintenance of existing plant thus appears to accelerate rate base growth. 
  9. http://www.ssrllc.com/publication/antiquated-power-grids-what-can-age-of-plant-tell-us-about-future-rate-base-growth/ 
  10. http://www.ssrllc.com/publication/antiquated-power-grids-what-can-age-of-plant-tell-us-about-future-rate-base-growth/ 
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