Is This the Golden Age of Electric Utilities? A Primer on Historical and Forecast Rate Base Growth

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Eric Selmon

Office: +1-646-843-7200

Email: eselmon@ssrllc.com

Hugh Wynne

Office: +1-203-901-1624

Email: hwynne@ssrllc.com

SEE LAST PAGE OF THIS REPORT FOR IMPORTANT DISCLOSURES

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September 13, 2016

Is This the Golden Age of Electric Utilities?

A Primer on Historical and Forecast Rate Base Growth

This note represents the first in a series analyzing utility rate base growth across the industry and at individual utilities, with the objective of identifying utilities that may be at inflection points in the growth of rate base, and therefore regulated earnings, and whose change in outlook has not yet been properly capitalized by the equity market.

  • In this note we identify those utilities that (i) derive a large proportion of consolidated earnings from regulated electric operations, (ii) are approaching an inflection point in rate base growth, and (iii) whose share prices seem not to capitalize the impending change in rate base growth.
  • Based on utilities’ announced capex plans, we forecast growth in aggregate electric rate base of ~6% p.a. over 2016-2020, in line with the 6% growth realized over the last five years.
  • Among those companies whose earnings derive predominantly from regulated electric utilities, however, there are several where we expect a significant acceleration or deceleration of rate base growth over 2015-2018.
    • Four stocks that apparently fail to fully price in this expected acceleration in rate base growth are AEE, ED, EIX and PCG.
      • AGR also looks attractive on these metrics, but derives nearly half of its earnings from its gas utility and unregulated operations.
    • Stocks that appear to fail to price in an expected deceleration are ALE, NWE and POR.
  • Longer term, we believe the risk of deceleration in rate base growth is highest in the transmission and generation segments and lowest in distribution. Over the last 10 years, transmission rate base expanded at 10.2% p.a. and generation rate base by 7.7% p.a., even as retail electricity revenues rose by only 3.8% p.a. Growth in distribution rate base was 4.3% p.a.
    • Transmission now accounts for 25% of aggregate electric rate base, its highest level in three decades and well above its 1998-2015 average of 19%. Distribution now comprises 42% of rate base, the lowest since 1992, and well below its 1988-2015 average of 47%.
  • Over the longer term, companies highly reliant on transmission capex for growth may be vulnerable, such as ALE, PEG, and AEP.
  • Firms whose growth relies on distribution capex may benefit from longer growth trajectories and could see an improvement in their relative rankings as investment in generation and transmission slows. Principal among these are ED, EIX, EXC, and AGR.

Exhibit 1: Stocks Screening Favorably and Unfavorably on Outlook for Rate Base Growth


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

Exhibit 2: Heat Map: Preferences Among Utilities, IPP and Clean Technology

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

Executive Summary

Growth in rate base is one of the fundamental drivers of long term earnings growth among regulated electric utilities. As set out in Exhibit 4, a regression analysis of the five year CAGR in electric rate base against the five year CAGR of electric operating income of U.S. investor owned utilities results in an r-squared of 0.31, suggesting that rate base growth explains approximately a third of the growth in operating income among electric utilities. Other key drivers of long term earnings growth include the frequency with which individual utilities file rate cases to adjust their regulated revenues to the reflect the rise in rate base; changes in the allowed return on equity used by regulators to set utilities’ allowed revenues in these rate cases; and utilities’ success or failure in realizing that allowed return through the control of operating and financial expenses. Looking ahead, we expect rate base growth will be an even more important driver of earnings growth as the decline of allowed ROEs levels off and the frequency of rate case filings continues at its current high level.

In this note, we provide the context in which to assess utilities’ expected growth in regulated rate base. We examine the historical rate of growth in the electric rate base of U.S. utilities, both in aggregate and by class of asset; rank the various utilities by their historical growth in rate base; assess the cyclicality of that growth; and compare these historical growth rates with the likely future growth of rate base as estimated based upon managements’ capex plans. We will focus in particular on identifying those companies whose forecast growth in rate base diverges sharply from what they have achieved historically and which investors may have come to expect, possibly creating valuation anomalies.

The historical rate of growth of rate base plus CWIP is illustrated in Exhibits 6 through 8. Exhibit 6 presents the annual rate of change; this has been highly volatile and has frequently followed a cyclical pattern. Even measured over long periods of time, the volatility of rate base growth is evident. As illustrated in Exhibit 7, from 1990 through 2000, the compound annual growth rate of rate base plus CWIP was 0.9% p.a.; over the period from 2000 through 2015, this accelerated to 6.5% p.a. This swing in the rate of growth of rate base plus CWIP is even more marked when put in the context of nominal GDP: while the growth of rate base plus CWIP fell far behind that of nominal GDP from 1990-2000, expanding at 0.9% p.a. as against 5.8% for nominal GDP, it materially outpaced nominal GDP over the subsequent 15 years, expanding at 6.5% p.a. as against only 3.8% for nominal GDP.

Even more volatile than the growth in aggregate electric rate base and CWIP has been the rate of growth of certain of its component asset classes. This is illustrated in Exhibit 7. As can be seen there, generation rate base declined at a 2.8% compound annual rate over the decade from 1990 through 2000, before recovering at a compound annual rate of 7.1% over the subsequent 15 years (2000-2015). Growth in transmission rate base was only 1.4% p.a. in the decade from 1990 through 2000, but accelerated to 8.4% p.a. over the subsequent 15 years and to 11.3% p.a. from 2010-2015. Of the three principal asset classes in electric rate base, distribution has been by far the most stable. Distribution rate base expanded at 4.4% p.a. over the decade from 1990 through 2000, decelerating slightly to 4.1% over 2000-2015.

We doubt that the booms in generation and transmission capex can be sustained. Over the last 10 years, transmission rate base has expanded at a 10.2% CAGR and generation rate base by 7.7% p.a.; retail electricity revenues, by contrast, rose by only 3.8% p.a., and nominal GDP by just 3.3% p.a. Measured in real terms, growth in the U.S. power sector was also very modest over this period, with peak power demand growing by only 0.6% p.a.

Having grown as long and as rapidly as they have, transmission and generation rate base now comprise a higher proportion of total electric rate base than they have in decades. At 25% the contribution of transmission to total electric rate base has never been higher (see Exhibit 9); its average share of total rate for the period 1988-2015 is only 19%. Generation now represents 34% of total electric rate base, its highest level since 1997. Conversely, the share of distribution in total electric rate base, at 42%, is at its lowest level since 1992 and well below its long term (1988-2015) average of 47%.

We have assessed the outlook for industry-wide rate base growth over the next five years (2016-2020). Our estimates of future rate base are based upon (i) the year-end 2015 rate base of the various investor owned electric utilities, (ii) the capital expenditure plans of these utilities over 2016-2020, as disclosed by management in SEC filings and investor presentations, (iii) expected depreciation in these years at each utility’s current depreciation rate, and (iv) the net change in deferred taxes (an offset to rate base) resulting from difference in tax and GAAP depreciation rates, the 50% bonus depreciation allowed upon the entry into service of new utility assets, and the reversal of these effects for prior years’ investments.

Our estimate of the growth in the aggregate electric rate base of U.S. investor owned utilities is presented in Exhibit 10. As can be seen there, our forecast is for rate base to grow at a rate (6.1% p.a.) that is little changed from that of the last five years (6.1%). Our forecast rate of growth is also broadly consistent with the historical CAGR in the industry’s electric rate base over 2000-2015 (6.5%).

The good times for the electric utilities sector, in other words, are expected to roll on for another five years. Within the sector, however, there are several companies whose earnings derive predominantly from regulated electric utilities where we expect a significant acceleration or deceleration of rate base growth over 2015-2018. The right hand column of Exhibit 3 highlights in green those companies whose rate base growth over the next three years is expected to show the greatest acceleration relative to that realized over the last three years. Companies with the sharpest deceleration in expected rate

Exhibit 3: Stock Selection Matrix — Stocks Screening Favorably Highlighted in Green, Stocks Screening Unfavorably Highlighted in Red

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

base growth, measured on the same basis, are highlighted in red. Four stocks that apparently fail to price in a sharp expected acceleration in rate base growth are AEE, ED, EIX and PCG. AGR also looks attractive on these metrics, but nearly half of its earnings derive from its gas utility and unregulated operations. Management’s consolidated earnings guidance suggests that these segments will not grow as quickly as the electric utility business. Stocks that in our view fail to price in a sharp expected deceleration of rate base growth are ALE, NWE and POR.

Finally, as noted above, we are skeptical that the decade-long booms in transmission and generation rate base can be sustained, or that growth in distribution capex will lag that of aggregate rate base indefinitely. To help investors assess the implications for individual stocks, Exhibit 13 breaks down the planned capital expenditures of the publicly traded U.S. electric utilities into their generation, transmission and distribution components, while Exhibits 14 through 16 graphically illustrate which utilities rely most and least heavily on generation, transmission and distribution capex to achieve their planned rate base growth over 2016-2020. Companies whose planned rate base growth is highly reliant on transmission and generation (such as ALE, PEG and AEP with respect to transmission and SCG, POR, NWE and SO with respect to generation) may face a challenge in sustaining current growth rates beyond 2020. Companies whose rate base growth is a function primarily of distribution capex may thus have longer and more sustainable growth trajectories, and could see an improvement in the relative rankings as investment in generation and transmission slows. Principal among these are ED, EIX, EXC, and AGR.

Overview

Growth in rate base is one of the fundamental drivers of long term earnings growth among regulated electric utilities.[1] As set out in Exhibit 4, a regression analysis of the five year CAGR in electric rate base against the five year CAGR of electric operating income of U.S. investor owned utilities results in an r-squared of 0.31, suggesting that rate base growth explains approximately a third of the growth in operating income among electric utilities. Other key drivers of long term earnings growth include the frequency with which individual utilities file rate cases to adjust their regulated revenues to the reflect the rise in rate base; changes in the allowed return on equity used by regulators to set utilities’ allowed revenues in these rate cases; and utilities’ success or failure in realizing that allowed return through the control of operating and financial expenses. Looking ahead, we expect rate base growth will be an even more important driver of earnings growth as the decline of allowed ROEs levels off and the frequency of rate case filings continues at its current high level.

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 so much more difficult to predict. At the annual financial conference of the Edison Electric Institute in November, rate base forecasts will feature prominently in management presentations and discussions with investors.

In this note, therefore, we provide the context in which to understand and assess management’s disclosures regarding growth in regulated electric rate base. We examine the historical rate of growth in the electric rate base of U.S. investor owned utilities, both in aggregate and by class of asset; rank the various investor owned utilities by their historical growth in rate base; assess the cyclicality of that growth; and compare these historical growth rates with the likely future growth of rate base as estimated based upon managements’ capex plans. We will focus in particular on identifying those companies whose forecast growth in rate base diverges sharply from what they have achieved historically and which investors may have come to expect, possibly creating valuation anomalies.

In subsequent notes in this rate base primer series, we plan to assess the risks surrounding management’s forecasts of rate base growth, including the impact on customer bills and the potential regulatory response; the ability to fund this growth internally and thus avoid the dilutive effect of equity issuance or holding company borrowings; the composition of planned capital expenditures, and the weight in these of assets classes, such as generation, that carry higher construction, operation, environmental and regulatory risks. We also plan to explore the long term drivers of growth in rate base, including average age of plant; inflation’s impact on the cost of replacements; changes in generation technology; investment in emissions controls; upgrades to metering and distribution systems; economic and demographic growth; and trends in energy efficiency. Each of these analyses will provide additional criteria for investors to use in their analysis and selection of utility stocks.

Exhibit 4: The Relationship of Rate Base Growth to Operating Income Growth at Investor Owned Electric Utilities in the United States, 1993-2013

Source: FERC Form 1, SNL, SSR analysis

What Can We Learn from Patterns in the Growth of Electric Rate Base Over the Last 20 Years?

We define electric rate base as a utility’s (i) net property, plant and equipment deployed in the provision of electric service, less (ii) its net deferred tax liability from the accelerated depreciation, for tax purposes, of electric plant in service. Because the latter primarily reflects taxes expensed but not yet paid, and thus requiring no shareholder capital, regulators generally will not allow utilities to earn a return on the portion of their assets funded by deferred taxes. Exact rate base definitions vary by jurisdiction, but we have chosen the two components universally included in rate base calculations.

When assessing the growth of rate base as a driver of earnings, however, we have included in our calculations construction work in progress or CWIP. While CWIP is not strictly part of rate base, which includes only utility plant that is “used and useful” and thus excludes assets under construction, common regulatory practice is to allow utilities to earn a return on CWIP (termed “allowance for funds used during construction” or AFUDC). For purposes of estimating the potential regulated earnings of individual utilities and the industry as a whole, we believe the best approach is to include both rate base and CWIP in our analysis.

The data used in our analysis is derived from utilities’ FERC Form 1 filings, annual financial statements that regulated, investor owned utilities must file with the Federal Energy Regulatory Commission using standard accounting categories and practices prescribed by the Commission. The financial statements prepared by utilities in compliance with FERC Form 1 standards present segment and operational data largely lacking from these companies’ SEC filings. As result, they allow a breakdown of a utility’s property, plant and equipment into electric and gas assets and further into standard sub-categories. In the case of electric utility plant, these include generation, transmission, distribution, and CWIP.

Time series data on electric rate base derived from utilities’ historical FERC Form 1 financials are subject to certain distortions attributable to the deregulation of utility generating assets by a number of states in the final years of the last century. In most states that deregulated generation, utilities were required to divest their generation assets or to transfer these to independent subsidiaries that would no longer be subject to rate regulation by state authorities. The result of these divestitures and asset transfers was materially to reduce the value of generation assets included in electric rate base. Other states allowed utilities to retain ownership of deregulated generation assets, but the utilities were no longer authorized to earn regulated returns on these assets, thus eliminating regulated earnings on generation rate base.

Our objective is to use historical data on regulated rate base to create a framework to assess the potential growth of rate base and regulated earnings in future years. We have therefore stripped out of our historical data any generation plant reported in utilities’ historical FERC Form 1 filings which is no longer subject to state rate regulation. As a result, our estimate of historical rate base captures only the continuously the assets of the electric utility industry continuously regulated during the period of our analysis, including the transmission and distribution assets of utilities whose generation has been deregulated and the production, transmission and distribution assets of utilities whose generation remains regulated.

The chart in Exhibit 5 illustrates the aggregate electric rate base plus construction work in progress of U.S. investor owned regulated utilities since 1988. As can be seen there, the sum of electric rate base and construction work in progress (hereafter, “rate base plus CWIP”) changed very little from 1988 through 1999, remaining at approximately $200 billion dollars for over a decade. Beginning in 2000, however, the rate base plus CWIP of U.S. investor owned utilities began a period of steady expansion that has continued and indeed accelerated over the last 15 years. It now exceeds $540 billion, an increase of more than 150% in 15 years.

Exhibit 5: Aggregate Electric Rate Base of U.S. Investor Owned Utilities by Asset Category ($ Billions) (1)

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  1. Includes construction work in progress (CWIP)

Source: FERC Form 1, SNL, SSR Analysis

The historical rate of growth of rate base plus CWIP is illustrated in Exhibits 6 through 8. Exhibit 6 presents the annual rate of change; this has been highly volatile and has frequently followed a cyclical pattern. Even when measured over long periods of time, the volatility of rate base growth is evident. As illustrated in Exhibit 7, from 1990 through 2000, the compound annual growth rate of rate base plus CWIP was 0.9% p.a.; over the period from 2000 through 2015, this accelerated to 6.5% p.a. This swing in the rate of growth of rate base plus CWIP is even more marked when put in the context of

Exhibit 6: Annual % Growth in Aggregate Electric Rate Base Plus CWIP of U.S. Investor Owned Utilities (1)


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  1. Includes construction work in progress (CWIP)

Source: FERC Form 1, SNL, SSR Analysis

Exhibit 7: CAGR in Electric Rate Base by Asset Class Over Various Periods

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  1. Total includes construction work in progress

Source: FERC Form 1, Bureau of Economic Analysis, SNL, SSR analysis

nominal GDP: the growth of rate base plus CWIP fell far behind that of nominal GDP from 1990-2000, expanding at an 0.9% CAGR as against 5.8% for nominal GDP, but then materially outpaced nominal GDP over the next 15 years, growing at an average annual rate of 6.5% as against only 3.8% for nominal GDP.

Even more volatile than the growth in aggregate electric rate base and CWIP has been the rate of growth of certain of its component asset classes. This is best illustrated in Exhibit 7. As can be seen there, generation rate base declined at a 2.8% compound annual rate over the decade from 1990 through 2000, before recovering at a compound annual rate of 7.1% over the next 15 years (2000-2015). Growth in transmission rate base was only 1.4% p.a. in the decade from 1990 through 2000, but accelerated to 8.4% p.a. over the next 15 years. Of the three principal asset classes in electric rate base, distribution has been by far the most stable. The growth of distribution rate base, by contrast, has been far more stable; it expanded at 4.4% p.a. over the decade from 1990 through 2000, decelerating slightly to 4.1% over 2000-2015.

The long term data on electric rate base thus suggest a tendency towards long boom and bust cycles in generation and transmission, in turn driving volatility in the growth of aggregate rate base plus CWIP, contrasting with a tendency towards relatively stability in the rate of growth of distribution assets. This may reflect the nature of the investment decision making with respect to these different asset classes. Investment in generation and transmission tends to involve large capital projects with long permitting and construction periods; their planning, therefore, is driven by forecasts of long term growth in peak power demand. Since at least 1970, the industry has tended to get these forecasts wrong, projecting historically rapid rates of power demand growth into the future even as load growth entered a period of secular decline. This tendency to overestimate future load growth has contributed to a pattern of overbuilding capacity followed by long periods of little capex during which the overbuild is absorbed. Investment in distribution assets, by contrast, involves much smaller capital outlays and very short permitting and construction period. Capital expenditures can thus be planned on a shorter term basis in response to the construction of new residential or commercial buildings, or when equipment fails or seems likely to do so in the near future.

Over the last quarter century, a second contributing factor to the volatility of investment in generation and transmission has been government policy. The move by many states to deregulate generation in the 1990s depressed utility investment in power plants, as managements sought to minimize their exposure to this asset class at a time of widespread deregulation. It was not uncommon at the time for regulated utilities to defer the construction of new power plants and rather to meet their incremental capacity requirements through power purchase agreements with independent power producers (IPPs). Some utilities also sold or wrote off generation assets in anticipation of deregulation, further reducing their owned capacity. With the California energy crisis of 2000-2001, which followed deregulation in that state by five years and triggered rolling blackouts in San Francisco and Los Angeles, the impetus towards deregulation slowed dramatically, and by 2003 utilities were once again expanding their generation fleets. In addition, the volatility of energy and power prices since 2000 has also encourage regulators and vertically integrated electric utilities to increase utility ownership of generation and reduce reliance on purchased power.

Similarly, the boom in transmission capex over the last decade reflects the incentives for transmission investment introduced by FERC after the blackout in the Northeast in 2003 highlighted the age of and limited historical investment in the transmission grid. FERC introduced substantially higher ROEs for new transmission projects, as well as mechanisms to ensure recovery of development costs on cancelled projects, reducing utilities’ risk and increasing their prospective earnings on transmission capex. Also supportive of transmission investment was the formation of regional transmission organizations in the states that deregulated power generation, as the historical model of vertically integrated generation and transmission systems, housed within a single regulated utility, was replaced with a focus on regional integration of competitive generation resources and planning across state borders. The spread of state renewable portfolio standards, requiring utilities to procure a stipulated percentage of the electricity they supply to customers from renewable resources. This in turn required heavy investment in new transmission lines to connect population centers with remote renewable generating plants, including solar farms in the desert Southwest and wind farms on the Great Plains. Finally, transmission investment accelerated as power prices fell steeply after 2008 and a number of utilities with large unregulated power generation fleets at the time (AEE, AEP, ETR, EXC, FE, PEG and PPL), began to look for regulated investment opportunities. These seven utilities accounted for ~15% of transmission rate base growth from 2000-10, ~35% from 2010-15 and expected to account for over 45% of transmission growth from 2015-20.

We doubt that the booms in generation and transmission capex can be sustained. Over the last 10 years, transmission rate base has expanded at a 10.2% CAGR and generation rate base by 7.7% p.a.; retail electricity revenues, by contrast, rose by only 3.8% p.a., and nominal GDP by just 3.3% p.a. Measured in real terms, growth in the U.S. power sector was also very modest over this period, with peak power demand growing by only 0.6% p.a.

Having grown as long and as rapidly as they have, transmission and generation rate base now comprise a higher proportion of total electric rate base than they have in decades. At 25% the contribution of transmission to total electric rate base has never been higher (see Exhibit 9); its average share of total rate for the period 1988-2015 is only 19%. Generation now represents 34% of total electric rate base, its highest level since 1997. Conversely, the share of distribution in total electric rate base, at 42%, is at its lowest level since 1992 and well below its long term (1988-2015) average of 47%.

Exhibit 8: Annual % Growth in Total Electric Rate Base of Investor Owned Utilities by Asset Class

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Source: FERC Form 1, SNL, SSR analysis

Exhibit 9: Breakdown of Total Electric Rate Base of Investor Owned Utilities by Asset Class (%)


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Source: FERC Form 1, SNL, SSR analysis

To conclude this discussion of the growth in the electric rate base of U.S. investor owned utilities, we have assessed the outlook for industry-wide rate base growth over the next five years (2016-2020). Our estimates of future rate base are based upon (i) the year-end 2015 rate base of the various investor owned electric utilities, (ii) the capital expenditure plans of these utilities over 2016-2020, as disclosed by management in SEC filings and investor presentations, (iii) expected depreciation in these years at each utility’s current depreciation rate, and (iv) the net change in deferred taxes (an offset to rate base) resulting from difference in tax and GAAP depreciation rates, the 50% bonus depreciation allowed upon the entry into service of new utility assets, and the reversal of these effects for prior years investments.

Our estimate of the growth in the aggregate electric rate base of U.S. investor owned utilities is presented in Exhibit 10. As can be seen there, our forecast is for rate base to grow at a rate (6.2% p.a.) that is little changed from that of the last five years (6.1%). Our forecast rate of growth is also broadly consistent with the historical CAGR in the industry’s electric rate base over 2000-2015 (6.5%).

The good times, in other words, are expected to roll on for another five years. In the next section we will assess which companies are best positioned to participate in the ongoing expansion of the industry.

Exhibit 10: Historical and Estimated Growth of Aggregate Electric Rate Base (2005-2020) (1)

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  1. 2016-2020 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

Rate Base Growth by Company

The volatility and apparent cyclicality of aggregate electric rate base, and particularly in the generation and transmission segments, is also evident at the level of individual utilities. In Exhibit 11, we provide a quintile ranking of the publicly traded investor-owned electric utilities based upon the rate of growth in their electric rate base over four successive five year periods: 1995-2000, 2000-2005, 2005-2010, and 2010-2015. As can be seen there, the norm is for a company’s quintile ranking to change rather than persist from one five-year period to the next. Moreover, when a company’s quintile ranking changes, it often does so dramatically. To illustrate this, consider that across the four successive five year periods, and the 40 plus utilities listed, there are approximately 120 opportunities for quintile rankings to change; in 77% of these opportunities, quintile rankings did change. Of the approximately 120 opportunities for quintile rankings to change, in 32% of these occasions there was a change of one quintile move, but in 45% the change was of two quintiles or more.

From an investor’s perspective, the implication seems to be that within the historically volatile and frequently cyclical trend in electric rate base growth, the ability of individual utilities to benefit from this growth is itself cyclical. Those companies with the most rapid rate base growth in one five-year period are unlikely to persist in the pole position in the next, and those at the bottom are also likely to experience a recovery in growth over time.

Given the historical cyclicality of individual utilities’ rate base growth, it is to be expected that many utilities that have realized top quintile growth in electric rate base over the last five years may see this growth slow materially over the next five, while utilities whose rate base growth has ranked in the bottom quintile may see a material improvement. Our forecasts of rate base growth by company suggest that this will indeed be the case (compare the right hand columns of Exhibit 11).

Critically, there are several companies whose earnings derive predominantly from regulated electric utilities where we expect a significant acceleration or deceleration of rate base growth over 2015-2018. The right hand column of Exhibit 12 highlights in green those companies whose rate base growth over the next three years is expected to show the greatest acceleration relative to that realized over the last three years. Companies with the sharpest deceleration in expected rate base growth, measured on the same basis, are highlighted in red. Four stocks that apparently fail to price in a sharp expected acceleration in rate base growth are AEE, ED, EIX and PCG. AGR also looks attractive on these metrics, but derives nearly half of its earnings from its unregulated and gas operations. Stocks that in our view fail to price in a sharp expected deceleration of rate base growth are ALE, NWE and POR.

Exhibit 11: Quintile Ranking of Utilities Based Upon Five Year CAGR in Electric Rate Base Plus CWIP (1)

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

Exhibit 12: Stock Selection Matrix — Stocks Screening Favorably Highlighted in Green, Stocks Screening Unfavorably Highlighted in Red


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

The Risks Attending Forecast Growth in Rate Base

In an industry as capital intensive as power generation, transmission and distribution, growth in rate base is not achieved without incurring substantial risk in the permitting and construction of new utility plant. In assessing investment opportunities across the electric utility industry, therefore, investors must weigh not only the growth potential of individual utilities but also the permitting, construction, regulatory, legal and financial risks that these companies take to realize this growth.

Historically in the U.S. utility industry, the most substantial risks have attended the construction of generation plant. This largely reflects the technical complexity and substantial cost of new coal and nuclear power plants. Despite having built and operated six nuclear power plants, Southern Company has encountered significant technical difficulties in the construction of two new nuclear units at Plant Vogtle, resulting in material construction delays and cost overruns. Exposure to these risks is only increased when utilities deploy innovative generation technologies, such as the integrated gasification combined cycle plants built by Duke Energy at Edwardsport, Indiana and Southern at Kemper County, Mississippi.

The huge capital cost of new nuclear and coal fired power stations often implies that the financial consequences of construction cost overruns and completion delays are material to shareholders. They are also material to ratepayers, resulting in a level of regulatory scrutiny and political controversy that would be unusual for less costly projects in the transmission or distribution segments. Major generation projects can also be the subject of legal challenges by private parties, such as environmental groups seeking to block the construction of new coal fired power plants, often causing material delays; AEP’s Turk Power Plant in Arkansas is a case in point.

High voltage transmission projects tend to be far less costly and technically complex than nuclear or coal fired power plants, and thus are far less likely to give rise to construction delays and cost overruns that are material to shareholders. They are, however, notoriously difficult to permit, reflecting the need to secure rights of way and construction permits from the many landowners and municipalities across the length of the line. (A high voltage transmission line built by American Electric Power to connect its Ohio generating fleet with customers in Virginia took eight years to permit but only one year to build). Companies for whom large transmission projects are a primary driver of rate base growth can thus be at risk of material delays in permitting these project and hence in completing the associated capital expenditures. The recent experience of Southern California Edison with its Tehachapi and West of Devers transmission projects is a case in point.

Finally, capital expenditure on distribution tends to carry the lowest construction, financial and regulatory risk of any category of utility plant. Distribution projects tend not to be technically challenging, are individually small, and can generally be built quickly. Not only are cost overruns and completion delays less likely to arise as a result, but the small size of individual distribution projects implies that their financial consequences will be less material. Similar considerations tend to lead to less aggressive regulatory oversight of distribution capex. Finally, legal challenges to utilities’ land use or environmental permits tend not to be a consideration.

For these reasons, we believe rate base growth driven by generation capex implies a far higher level of financial risk to shareholders that rate base growth driven by transmission and distribution. However, capex programs that rely heavily on transmission projects, as is increasingly common among U.S utilities, are prone to completion delays, creating the risk for investors that the growth expectations capitalized in a utility’s share price may not be realized. For these reasons, the mix of generation, transmission and distribution projects in a utility’s capital expenditure programs has material implications for the financial risk borne by its shareholders.

To help investors assess these risks, Exhibit 13 breaks down the planned capital expenditures of the publicly traded U.S. electric utilities into their generation, transmission and distribution components. Exhibits 14 through 16 graphically illustrate which utilities rely most and least heavily on generation, transmission and distribution capex to achieve their planned rate base growth over 2016-2020. As can be seen there, at SCG, POR, NWE and SO, over two thirds of planned rate base growth over 2016-2020 is attributable to generation capex (see Exhibit 14). By contrast, ED, EIX, EXC, HIFR and AGR are in the opposite situation, relying on distribution capex for 65% or more of planned rate base growth over 2016-2020 (see Exhibit 16).

Exhibit 13: Breakdown of 2016-2020 Growth in Electric Rate Base by Class of Asset


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Source: FERC Form 1, SNL, SSR analysis

Exhibit 14: Contribution of Generation to Total Rate Base Growth, 2016-2020

Source: FERC Form 1, SNL, SSR analysis

Exhibit 15: Contribution of Transmission to Total Rate Base Growth, 2016-2020


Source: FERC Form 1, SNL, SSR analysis

Exhibit 16: Contribution of Distribution to Total Rate Base Growth, 2016-2020

Source: FERC Form 1, SNL, SSR analysis

A second reason to consider the breakdown of planned capital expenditures across generation, transmission and distribution is to identify companies whose reliance upon a single segment may represent a risk to their long term growth. We noted above that the booms over the last decade in generation and transmission capex are unlikely to be sustained. Over the last 10 years, transmission rate base has expanded at a compound annual rate of 10.2% p.a., while generation rate base has grown by 7.7% annually (see Exhibit 7). Over this same period, retail electricity revenues, rose by only 3.8% p.a., and nominal GDP by just 3.3% p.a. As a result of these booms in investment, transmission and generation rate base now comprise a higher proportion of total electric rate base than they have in decades. At 25% the contribution of transmission to total electric rate base has never been higher (see Exhibit 9); its average share of total rate for the period 1988-2015 is only 19%. Generation now represents 34% of total electric rate base, its highest level since 1997. Companies whose planned rate base growth is highly reliant on these two sectors (such as SCG, POR, NWE and SO with respect to generation, and ALE, PEG and AEP with respect to transmission) may thus face a challenge in sustaining current growth rates beyond 2020.

Conversely, the share of distribution in total electric rate base, at 42%, is at its lowest level since 1992 and well below its long term (1988-2015) average of 47%. Companies whose rate base growth is a function primarily of distribution capex may thus have longer and more sustainable growth trajectories, and could see an improvement in the relative rankings as investment in generation and transmission slows. Principal among these are ED, EIX, EXC, and AGR (see Exhibit 16).

Finally, investors may be well advised to consider the relative age of each utility’s property, plant and equipment when assessing the prospects for rapid future growth in rate base. We believe this is most relevant for transmission, where our proxy for average age of plant has declined from by almost 50% from its peak in 2001, is nearing the lowest it has been during our analysis period and is continuing to decline. A company that relies heavily on transmission capex for its growth, but whose transmission plant is significantly newer, on average, than that of the industry as a whole, is at greater risk of a slowdown in growth than one whose transmission plants is materially older than average and arguably in need of renewal. Exhibit 17, therefore, presents our estimate of the age of each investor owned utility’s transmission plant relative to the industry average. (As a proxy for the age of transmission plant, we have divided each utility’s accumulated depreciation for its transmission segment by its 2015 transmission depreciation expense.)

We believe the combination of relatively new utility plant and high levels of investment implies a higher risk to future growth than a combination of old utility plant and low levels of investment. At Allete, for example, transmission capex underpins 88% of planned rate base growth over 2016-2020; yet the average age of Allete’s transmission assets in only 80% of the industry average. This combination would seem to imply that a slowdown in transmission capex is probable .

Exhibit 17: Average Age of Transmission Plant, Expressed as a Percentage of the Industry Average

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Source: FERC Form 1, SNL, SSR analysis

Summary & Conclusions

In this note we have identified those utilities that (i) derive a large proportion of consolidated earnings from regulated electric operations, (ii) are approaching an inflection point in rate base growth, and (iii) whose share prices seem not to capitalize the impending change in rate base growth.

Among those companies whose earnings derive predominantly from regulated electric utilities, there are several where we expect a significant acceleration or deceleration of rate base growth over 2015-2018. Four stocks that apparently fail to fully price in this expected acceleration in rate base growth are AEE, ED, EIX and PCG. AGR also looks attractive on these metrics, but derives nearly half of its earnings from its gas utility and unregulated operations. Stocks that appear to fail to price in an expected deceleration are ALE, NWE and POR.

Longer term, we believe the risk of deceleration in rate base growth is highest in the transmission and generation segments and lowest in distribution. Companies highly reliant on transmission capex, whose long term growth may be vulnerable as a result, include ALE, PEG, and AEP. Firms whose growth relies on distribution capex may benefit from longer growth trajectories and could see an improvement in their relative rankings as investment in generation and transmission slows. Principal among these are ED, EIX, EXC, and AGR.

Based on this analysis and an overall assessment of the companies, we see AEE, ED, EIX, PCG as attractive investments and recommend avoiding ALE, NWE and POR.

  • AEE’s rate base growth over the next 5 years will drive earnings growth almost as fast, but is trading in-line with the industry. This is partly due to the risks of lower ROE on its FERC regulated transmission and on its Illinois distribution rate base, which is tied to the 30-year Treasury yield, but this is already mostly reflected in consensus earnings forecasts.
  • ED is currently trading in line with industry valuation on 2018 earnings, but we believe consensus forecasts are low and do not fully reflect the growth in rate base and limited equity needs. ED is currently in a rate case and will face a penalty for the explosion in Harlem in 2014, but these overhangs should not impact our long-term earnings growth expectations.
  • EIX has had above average rate base growth for a number of years, but stumbled in recent years as it had to shut down the San Onofre nuclear power plant and remove it from rate base. As a result, EIX trades generally in line with sector valuations. Their expected rate base growth is strong even when reduced to reflect disallowances by regulators and should not require equity issuance.
  • PCG has traded at a discount to the sector since the San Bruno explosion in 2009. With this finally behind them and solid rate base growth ahead they should move up to trade in-line or, once they have a couple of years of clean execution, above the sector.
  • ALE is completing a period of rapid rate base growth and their future growth projects other than transmission are primarily post-2020. Without new projects, ALE could miss consensus through 2018 if economic growth and industrial demand (43% of demand) slow and will certainly disappoint beyond.
  • NWE’s rate base growth is slowing down in spite of additional generation they recently added to their forecasts. Of equal or greater concern is the fact that they have not been in for a rate case in several years, will need to file within the next few years and their allowed ROEs are above what they would likely be allowed in a new rate case.
  • POR has historically been conservative in their capex forecasts and have added as opportunities are finalized, however, the upside to their current forecast (and our rate base growth estimate) is new wind which is being questioned by the regulators and a Pacificorp, another utility in the state, saw its project denied. POR is trading at a meaningful premium to the sector with a high risk that they will disappoint.

©2016, 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. 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.
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