Why Rate Base Growth Will Far Outpace GDP, But Rates Will Not

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Eric Selmon

Tel: +1-646-843-7200

Email: eselmon@ssrllc.com

Hugh Wynne

Tel: +1-917-999-8556

Email: hwynne@ssrllc.com

SEE LAST PAGE OF THIS REPORT FOR IMPORTANT DISCLOSURES

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October 31, 2016

Why Rate Base Growth Will Far Outpace GDP, But Rates Will Not

U.S. regulated utilities are planning ~6% rate base growth through 2020. Our analysis suggests the impact on rates and bills will be highly manageable, with average residential bills rising by 1.8% p.a. and average electricity rates by 2.4% p.a. through 2020. These increases, roughly in line with inflation and well below expected growth in nominal GDP, are unlikely to engender material regulatory opposition. We therefore expect the industry to realize its planned rate base and earnings growth. Yet as highlighted in the summary below, individual utilities face varying levels of risk.

Portfolio Manager’s Summary

  • The growth in electric rate base of U.S. investor owned utilities (the invested capital on which the utilities are allowed to earn a regulated return) has averaged 6.5% p.a. over the 15 years from 2000 through 2015 – far outstripping the growth over this period in nominal GDP (3.8% p.a.).
  • Regulated utilities’ 6.5% compound annual growth in rate base over 2000-2015 was achieved while increasing average customer bills by only 1.3% p.a. Over 2010-2015, average customer bills did not increase at all, even as rate base expanded by 6.1% annually.
  • The capex plans of U.S. investor owned electric utilities imply 6.2% growth in aggregate rate base over 2015-2020. If, as implied by forward markets, the price of natural gas, long term interest rates, and the rate of inflation remain broadly stable over the next five years, we calculate that this growth can be achieved while raising average residential customer bills by only 1.8% p.a. and system average rates by only 2.4% – broadly in line with expected inflation and thus implying little regulatory risk.
  • EXC and PCG combine first quintile growth in rate base over 2015-2020 with relatively low annual increases in average residential bills. At both companies, bill increases over 2015-2020 are expected to fall in the second lowest quintile among their predominantly regulated peers. Also attractive on this basis may be AEP and EIX, which combine second quintile growth in rate base over 2015-2020 with average (middle quintile) increases in residential bills over the same period.
  • Facing the smallest increases in average residential bills over 2015-2020, we calculate, are HE (where growth in rooftop solar drives average residential bills down by 2.2% p.a.), ED (average bills up 0.2% p.a.), IDA (up 0.6% p.a.), POR (0.7%), OGE (1.1%), SO (1.1%), and FE (1.2%).
  • The largest increases in average residential bills will be required at LNT (up 4.3% p.a. over 2015-2020), DTE (up 3.4% p.a.), AVA (3.2%), AGR (2.9%), WR (2.8%), and SCG (2.7%)
    • If SCG’s recent election to deduct the costs of the new nuclear units at VC Summer is approved by the IRS, the growth in SCG’s residential bill growth rate will drop to 1.5% p.a. over 2015-2020. Growth in rate base, however, will also drop from 8.0% to 4.5% p.a. over that period.

Analyst’s Summary

The growth in electric rate base of U.S. investor owned utilities (the invested capital on which the utilities are allowed to earn a regulated return) has averaged 6.5% p.a. over the 15 years from 2000 through 2015 – far outstripping the growth over this period in nominal GDP (3.8% p.a.), retail electricity revenues (3.5% p.a.), retail electric customers (1.0% p.a.) and MWh sales of electricity to retail customers (0.5% p.a.). (See Exhibit 2.) Even more impressive, regulated utilities’ 6.5% compound annual growth in rate base over 2000-2015 was achieved while increasing average customer bills by only 1.3% p.a. – below the rate of inflation. Over 2010-2015, average customer bills did not increase at all, even as rate base expanded by 6.1% annually.

Looking back, the ability of the regulated electric utilities rapidly to expand their invested capital with little impact on customer bills reflects the following characteristics of the industry, illustrated in Exhibits 7 to 10:

    • The return of and on invested capital (the sum of depreciation and return on rate base) averaged just 25% of utilities’ revenues in over 2000-2015. Thus the 6.5% annual growth in rate base achieved over 2000-2015 required only a 1.6% average annual increase in total utility revenue to recover the increase in capital costs driven by rate base growth.
    • Even this modest annual increase in required revenue could be spread across an ever-expanding customer base. Over 2000-2015, utilities’ customer base grew at 1.0% p.a., implying the need for only a 0.6% annual increase in the average customer bill to recover the cost of rate base growth.
    • In fact, the revenue required by utilities for the return of and on invested capital lagged the growth of invested capital. Over 2000-2015, the growth in pre-tax return on rate base (4.8% p.a.) lagged the growth in rate base (6.5% p.a.) due to declining allowed returns on rate base over the period (see Exhibits 8 and 10). Similarly, the growth in depreciation expense (2.2% p.a.) materially lagged rate base growth, due in some cases to the extension of depreciation schedules for property, plant and equipment (e.g., NEE) and in others to the long lived nature of the assets receiving the bulk of new investment (e.g., AEP’s heavy investment in transmission).
    • The growth in non-fuel O&M (3.0% p.a.) also lagged the growth in rate base, as utilities achieved offsetting efficiencies or enjoyed economies of scale in the recovery of fixed costs.
    • Finally, and very importantly, utilities’ second largest cost category – fuel and purchased power, accounting for 34% of the total in 2015 – declined modestly over the fifteen years from 2000 through 2015, with a large increase through 2005 followed by a larger decline over 2008-2015.

If, as implied by forward markets, the price of natural gas, long term interest rates, and the rate of inflation remain broadly stable over the next five years, we calculate that U.S. investor owned electric utilities can enjoy 6.2% growth in aggregate rate base over 2015-2020 while raising average residential customer bills by only 1.8% p.a., and system average rates by only 2.4%. These increases, roughly in line with consensus estimates of the rate of inflation and well below expected growth in nominal GDP, are unlikely to engender material regulatory opposition. We therefore expect the industry to realize its planned rate base and earnings growth.

While these may be halcyon days for the industry as a whole, the regulatory risk faced by individual utilities – at least as measured by the expected impact on average system rate and average residential bills — varies widely. To help investors asses the regulatory risk associated with each utility’s rate base growth, Exhibit 12 and Exhibit 13 provide a comprehensive forecast of the impact on each utility’s average system rate and average residential bill of its disclosed capex program and corresponding rate base growth, as well the sensitivity to changes in allowed return on rate base, O&M inflation, MWh sales growth and residential customer usage.

As can be seen there, utilities facing particularly rapid rate base growth, a stagnant customer base, or an unusually high ratio of capital recovery costs to total revenue, may require more rapid increases in average bills and thus could face greater customer and regulator resistance to their required revenue increases. Principal among these, we expect, will be LNT (whose average residential bill we estimate must rise by 4.3% p.a. over 2015-2020), DTE (facing a 3.4% estimated annual increase in residential bills), AVA (3.2%), AGR (2.9%), WR (2.8%), and SCG (2.7%). However, if SCG’s recent election to deduct the costs of the new nuclear units at VC Summer are approved by the IRS, SCG’s residential bill growth rate will drop to 1.5%, while average rate base growth will drop from 8% to 4.5% annually over that period.

Likely to face the smallest increases in average residential bills, we calculate, are ED (whose average residential bill we estimate must rise by only 0.2% p.a. over 2015-2020), IDA (0.6%), POR (0.7%), OGE (1.1%), SO (1.1%), FE (1.2%) and, notably, HE, in whose service territory the growth of rooftop solar is expected to bring about a decline in average residential bills of 2.2% p.a. over 2015-2020.

Exhibit 14 ranks the publicly traded investor owned utilities into quintiles based on forecast rate base growth over 2015-2020 as well as on the impact of this rate base growth on the average system bundled rate and the average residential bill. EXC and PCG combine first quintile growth in rate base over 2015-2020 with relatively low annual increases in average residential bills. At both companies, residential bill increases over 2015-2020 are expected to fall in the second lowest quintile among their predominantly regulated peers. Also attractive on this basis may be AEP and EIX, which combine second quintile growth in rate base over 2015-2020 with average (middle quintile) increases in residential bills over the same period.

ETR also appears to be in an advantageous situation, enjoying second quintile rate base growth on while facing rates of increase in its average system rate and average residential bill that fall in the lowest and second lowest quintiles, respectively. However, the company recently disclosed $1.4 billion of additional O&M and capex required to improve the performance of the nuclear fleet. If regulators allow full recovery of these expenditures, the rate of increase in ETR’s average residential bill would accelerate from 1.8% to 2.1% p.a., pushing the increase in customer bills into the third quintile. There is also a risk that some portion of these increased expenditures may be disallowed.

Our relatively optimistic assessment of the impact of future rate base growth on average system rates and customer bills is at risk should utilities’ cost of fuel and purchased power significantly increase, in particular as a result of higher prices for natural gas. For vertically integrated utilities, we calculate that the impact on average residential bills of an increase in natural gas prices will be limited (see Exhibit 16), reflecting the fuel diversity of these companies’ generating fleets. The utilities that would face the greatest upward pressure on their average residential bills in the event of increase in the price of natural gas would be those that operate in states where generation has been deregulated (“T&D utilities”), and hence are not vertically integrated but rather deliver electricity generated by others (see Exhibit 17). Because wholesale power prices in deregulated states reflect the variable operating cost of the last generating unit dispatched to meet demand, and in most regions gas fired generators are on or near the margin, an increase in the price of natural gas has a larger impact on the price of purchased power than it does on the fuel cost of a diversified, regulated fleet.

We note, however, that in all states fuel and power costs are now a pass-through to customer bills. Thus, while an increase in the gas price could put upward pressure on customer bills, from a regulatory standpoint it would have no bearing on the rate cases in which utilities seek to recover the capital and O&M costs associated with rate base growth. The risk to earnings growth should thus be limited even for T&D utilities.

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

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

Details

The aggregate electric rate base of U.S. investor owned utilities (the invested capital on which utilities are allowed to earn a regulated return) has expanded at 6.5% p.a. over the 15 years from 2000 through 2015 – far outstripping the growth over this period in nominal GDP (3.8% p.a.), retail electricity revenues (3.5% p.a.), retail electric customers (1.0% p.a.) and MWh sales of electricity to retail customers (0.5% p.a.) (Exhibit 2.)

Exhibit 2: CAGR in Electric Rate Base of U.S. Investor Owned Utilities Compared to CAGRs of Their Retail MWh Sales, Retail Electric Customers and Retail Electricity Revenues (1), 2000-2015

  1. All data are for investor owned utilities only, with the exception of retail revenues, which are for the U.S. electric industry as a whole.

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

How does the invested capital of an industry that supplies an essential public service, and which achieved market saturation 60 years ago when the last rural areas were electrified, continue to outstrip the growth of GDP?

There are three principal reasons. First, due to the impact of inflation over the long useful life of utility plant (generally 30 to 40 years, depending on the type of asset), replacement capex consistently exceeds book depreciation, allowing rate base to grow even if a utility’s generation capacity and transmission and distribution network are physically unchanged. In the United States, the regulated rate base of investor owned utilities is roughly equivalent to the utility’s historical investment in property, plant and equipment, net of accumulated depreciation and reduced by the utility’s deferred tax liability.[1] Since the average age of property, plant and equipment at a utility can easily be 15 to 20 years, and there is no adjustment of the value of these assets for inflation, the depreciation charge taken by the company reflects on average the level of prices 15 to 20 years ago. Even at 2% inflation, the implication is that maintenance capital expenditures (as opposed to growth capex) can itself run 35% to 50% in excess of depreciation expense. The impact of historical inflation, we estimate, can add 1.0% to 1.5% p.a. to annual rate base growth.

Second, the U.S. power system has continued to grow in real terms. Customer growth over the last 15 years has averaged 1.0% p.a., while peak demand for power as well as MWh delivered have increased at ~0.5% annually. This growth in power demand and in the number of customers connected to the grid would be expected to drive growth in rate base of 0.5% to 1.0% annually, and probably a bit more, because at today’s prices the cost of connecting these new customers or adding new generation capacity will exceed the average historical cost embedded in rate base.

Third, much of the capital invested by the power industry in the current century has been spent not to increase the supply of electricity but rather to improve its reliability and mitigate its environmental impact. The last 15 years have seen slow demand growth but rapid technological change; during this period, often in response to federal and state mandates, the U.S. power generating fleet has made a radical shift toward lower emitting sources of power. Thus from 2000 to 2015, peak demand for electricity across the U.S. increased by 45 GW; the nation’s generation fleet, by contrast, expanded by a net 360 GW. Some 275 GW of new gas fired capacity was added, raising the national capacity margin from 16% to 21%, materially increasing system reserves and permitting the deployment of low emitting but intermittent renewable generation capacity. From 2000 through 2015, almost 100 GW of renewable capacity was added, increasing the share of renewable generation in total power output from less than 9% at the turn of the century to 15% by 2015. Even more impactful, a doubling in the output of the gas fired fleet over this period help bring about a reduction in the share of coal fired generation from over a half of the total in 2000 to only a third in 2015.

The cost of these investments was enormous, with ~$250 billion spent to expand the gas fired fleet, and over $175 billion to build out renewable generation. Other investments designed to mitigate the environmental impact rather than increase the supply of generation include the installation of flue gas desulfurization and other emissions control equipment on the nation’s coal fired generating fleet, at an estimated cost of over $50 billion, to bring these plants into compliance with the EPA’s increasingly stringent air emissions standards. To put the scale of these investments in perspective, we estimate the total regulated electric rate base of U.S. investor owned utilities, which supply ~65% of U.S. electricity customers, at only $550 billion.

In summary, the growth in aggregate electric rate base has benefited from continued albeit modest growth in customers, load and peak demand, and has enjoyed a tailwind from the tendency of book depreciation to understate the cost of maintenance capex. Equally important, however, the industry has been able to capitalize on the demands of federal and state policy makers to enhance system reliability by increasing reserve margins and improving the operation of regional power grids; reduce the emissions of the coal fired fleet; and accelerate the integration of zero-emission renewable generation. These demands, while transient, will continue to be important drivers of utility capex over the next five years.

As explained in our research note of September 13th, Is This the Golden Age of Electric Utilities?, we expect the growth in aggregate rate base of U.S. investor owned utilities to continue through 2020 at a pace similar to that of the last five years (see Exhibit 3). Our analysis of the annual financial filings made by U.S. investor owned utilities with the Federal Energy Regulatory Commission (FERC Form 1) suggests that the aggregate electric rate base of these companies has expanded at a compound annual rate of 6.1% over the period from 2010 through 2015. The capital expenditure plans of the publicly traded U.S. electric utilities are consistent with the continued expansion of their aggregate rate base over the next five years (2015-2020) at a rate of 6.2% p.a. [2]

Exhibit 3: Historical and Forecast Growth of the Aggregate Electric Rate Base of U.S. Investor Owned Utilities, 2010-2015 v. 2016-2020

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

Over the last five years, however, the U.S. investor owned utilities have faced an increasingly challenging environment in which to realize such rapid growth in rate base, and we expect these challenges to persist in the years ahead. In particular, growth in customers and MWh sales has decelerated markedly over the years from 2010 through 2015 relative to the period 2000-2010. As illustrated in Exhibit 4 below, MWh sales of electricity among investor owned utilities have contracted over the last five years, falling an average of 0.2% p.a. from 2010 through 2015; over the prior ten years, by contrast, MWh sales of electricity by these utilities had increased by 0.8% p.a. This slowdown in turn reflected a material decline in the rate of customer growth, from 1.2% to 0.5% p.a., possibly reflecting the impact of the Great Recession on both household and new business formation. Slowing labor force growth due to demographic trends, persistently high unemployment, and tighter mortgage lending standards have restrained the pace of new household formation for years after the recession ended, while sluggish GDP growth and more limited access to credit have slowed the creation of new businesses. Almost as important as slower customer growth has been the decline in usage per customer; over the years 2010-2015, usage per customer contracted at a rate of 0.7% p.a., as compared to a decline 0.3% p.a. over 2000-2010. This change may reflect in part the phase-out of traditional incandescent electric light bulbs over the years 2012-2014 and their replacement with significantly more efficient compact fluorescent and LED bulbs.

Exhibit 4: CAGR of Retail Electricity Customers, Usage per Customer, MWh Sales, Average Rates and Average Bills of U.S. Investor Owned Utilities, 2000-2010 vs. 2010-2015

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

Continued slow growth in customers and declining power demand could create significant difficulties for the U.S. investor owned utilities in realizing their planned growth in rate base, and thus in allowed earnings, over the next five years. Rate base growth in excess of 6% p.a. in the context of declining MWh sales should put material upward pressure on average rates. With customer growth running at only 0.5% p.a., the outlook for average customer bills is only slightly better. If these rate and bill increases are sufficiently large, ratepayer and regulator backlash could force utility managements to curtail planned capital expenditures or accept lower returns on these investments for some period of time.

To assess the extent of this risk, we have first analyzed the historical experience of U.S. investor owned utilities in recovering in regulated rates the capital and non-fuel O&M costs associated with their historical rate base growth. Second, we have modeled the expected impact of each utility’s proposed capital expenditures over 2015-2020, and the attendant increase in capital and O&M costs, on each company’s future rates and bills. In the discussion that follows we first present our historical analysis and then the implications of our forecast.

A hopeful precedent for utilities’ ability to realize rapid rate base growth while limiting the impact on customer bills can be found in the experience of the last 15 years. Over 2000-2015, the U.S. investor owned utilities achieved growth in aggregate electric rate base of 6.5% p.a. while increasing average customer bills by only 1.3% annually. Over 2010-2015, average customer bills did not increase at all, even as rate base expanded by 6.1% annually. (See Exhibits 4, 5 and 6).

Exhibit 5: CAGR of Revenues, Customers, Usage per Customer, MWh Sales, Average Rates and Average Bills of U.S. Investor Owned Utilities, 2000-2010 vs. 2010-2015

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

Exhibit 6: Average Residential and Commercial Bills of U.S. Investor Owned Utilities, 2000-2015

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Source: FERC Form 1, SNL, SSR analysis

Looking back, the ability of the regulated electric utilities rapidly to expand their invested capital with little impact on customer bills reflects the following characteristics of the industry, illustrated in Exhibits 7 to 10:

    • The return of and on invested capital (the sum of depreciation and return on rate base) averaged just 25% of utilities’ revenues in over 2000-2015. Thus the 6.5% annual growth in rate base achieved over 2000-2015 required only a 1.6% average annual increase in total utility revenue to recover the increase in capital costs driven by rate base growth.
    • Even this modest annual increase in required revenue could be spread across an ever-expanding customer base. Over 2000-2015, utilities’ customer base grew at 1.0% p.a., implying the need for only a 0.6% annual increase in the average customer bill to recover the cost of rate base growth.
    • In fact, the revenue required by utilities for the return of and on invested capital lagged the growth of invested capital. Over 2000-2015, the growth in pre-tax return on rate base (4.8% p.a.) lagged the growth in rate base (6.5% p.a.) due to declining allowed returns on rate base over the period (see Exhibits 8 and 10). Similarly, the growth in depreciation expense (2.2% p.a.) materially lagged rate base growth, due in some cases to the extension of depreciation schedules for property, plant and equipment (e.g., NEE) and in others to the long lived nature of the assets receiving the bulk of new investment (e.g., AEP’s heavy investment in transmission).
    • The growth in non-fuel O&M (3.0% p.a.) also lagged the growth in rate base, as utilities achieved offsetting efficiencies or enjoyed economies of scale in the recovery of fixed costs.
    • Finally, and very importantly, utilities’ second largest cost category – fuel and purchased power, accounting for 34% of the total in 2015 – declined modestly over the fifteen years from 2000 through 2015, with a large increase through 2005 followed by a larger decline over 2008-2015.

Exhibit 7: Breakdown of the Electric Income Statement of U.S. Investor Owned Utilities by Category of Cost, 2015

Source: FERC Form 1, SNL, SSR analysis

Exhibit 8: Compound Annual Growth in the Aggregate Rate Base and Key Components of the Electric Income Statement of U.S. Investor Owned Utilities, 2000-2015

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Source: FERC Form 1, SNL, SSR analysis

Exhibit 9: Key Components of the Electric Income Statement of U.S. Investor Owned Utilities, 2000-2015 (% of Electric Operating Revenues)

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

Exhibit 10: Average Allowed Return on Equity, Return on Rate Base and Equity Ratio Granted in Electric Utility Rate Cases by State Regulatory Commissions, 1990-2015

Source: SNL, SSR analysis

The benefit that utilities have historically enjoyed as a result of these factors points to potential risks going forward. These include a reversal of the trend, evident since 2008, towards lower fuel and purchased power costs; more rapid increases in non-fuel O&M as utilities’ efficiency gains begin to plateau and lower unemployment and tighter labor markets push labor costs higher; the possibility that rising long term interest rates drive up the required pre-tax return on rate base; and the end of the trend that saw depreciation expense rising less rapidly than rate base.

Other risks that analysts may wish to take into account when assessing the attractiveness of individual stocks include:

  • Rate base growth itself. While obviously enhancing the earnings growth prospects of a utility, more rapid rate base growth will in turn be associated with increased depreciation expense, return on rate base and non-fuel O&M, driving rates higher and increasing the risk of customer or regulatory backlash.
  • Growth in MWh sales. For any given level of rate base growth, a company with higher expected growth in MWh sales is likely to enjoy a slower rate of increase in the average system rate, lessening the impact on the cost of goods sold of its commercial and industrial customers and thus mitigating regulatory risk.
  • Customer growth. Similarly, for any given level of rate base growth, a company with higher customer growth would face a slower rate of increase in the average residential bills, lessening the risk of adverse customer and regulator reaction.
  • The proportion of capital cost in total revenues. A utility for whom depreciation expense and return on rate base (the return of and on capital invested) comprise a high proportion of total revenues will, for any given level of rate base growth, see a greater increase in average system rate and average customer bill than a utility for whom the ratio of capital costs to revenue is lower.
  • The ratio of the average residential utility bill to median household income in the utility’s service territory. Utilities whose residential customers pay a relatively high percentage of household income for electric service will tend to come under sharper regulatory scrutiny than those for whom this proportion is lower.

Exhibit 11 ranks the publicly traded investor owned utilities into quintiles on the basis of rate base growth over 2015-2020 as well as on each of the risk factors discussed above. A utility that ranks in the fourth or fifth (worst) quintiles on each of the four risk factors (e.g., AEE or GXP) arguably should face a materially higher degree of regulatory risk for any given level of rate base growth than its peers. Conversely, a utility ranking in the first (best) or second quintile on the four risk factors (e.g., NWE, PNM or XEL) should face fewer regulatory challenges for any given level of growth.

Exhibit 11: Regulated Electric Utilities Ranked by Rate Base Growth Prospects and Indicators of Attendant Regulatory Risk


Source: FERC Form 1, SNL, SSR analysis

Finally, we have tried to quantify for each individual utility the potential upward pressure on utility revenues and customer bills implied by its disclosed capital expenditure plans and consequent rate base growth. Specifically, we have modeled the revenue each utility would require to cover the increase in depreciation expense, pre-tax return on rate base, and non-fuel O&M costs that could be expected if the utility’s capital expenditure plan for the next five years is realized as planned. We then calculated the impact of this required revenue increase on the utility’s average system rate and average residential bill.

Importantly, the key assumption underlying our base case analysis is for little to change in the trajectory of the industry. As implied by forward markets, we have assumed that long term interest rates and thus utilities’ allowed return on rate base remain broadly stable over the next five years. We have also assumed no change in the depreciation rate applied by each utility. We have assumed non-fuel O&M costs rise in real terms with customer growth, and are in addition subject to 2% annual price inflation, consistent with the consensus expectations of Wall Street economists and with the experience of the utility industry as a whole over the last five years. We have assumed that customer growth at each utility continues at the same compound annual rate as the utility realized over the last five years. Similarly, we have assumed that the trend in usage per customer over the last five years also continues unchanged.

Given these assumptions, we calculate that U.S. investor owned utilities can realize 6.2% growth in aggregate electric rate base over 2015-2020 while raising average residential customer bills by only 1.8% p.a. and average electricity rates by 2.4% p.a. through 2020. This forecast of the average rate of increase in customer bills is broadly in line with consensus expectation of the rate of inflation and is equivalent to approximately half the consensus expectations of the rate of growth in nominal GDP. The implication would seem to be that, if financial, economic and industry conditions remain stable, growth in electric utility rate base can continue to at its 6% pace with little risk, on average, of customer or regulator push back.

While these may be halcyon days for the industry as a whole, the regulatory risk faced by individual utilities – at least as measured by the expected impact on average system rate and average residential bills — varies widely. To help investors asses the regulatory risk associated with each utility’s rate base growth, Exhibit 12 and Exhibit 13 provide a comprehensive forecast of the impact on each utility’s average system rate and average residential bill of its disclosed capex program and corresponding rate base growth, as well the sensitivity to changes in allowed return on rate base, O&M inflation, MWh sales growth and residential customer usage.

As can be seen there, utilities facing particularly rapid rate base growth, a stagnant customer base, or an unusually high ratio of capital recovery costs to total revenue, may require more rapid increases in average bills and thus could face greater customer and regulator resistance to their required revenue increases. Principal among these, we expect, will be LNT (whose average residential bill we estimate must rise by 4.3% p.a. over 2015-2020), DTE (facing a 3.4% estimated annual increase in residential bills), AVA (3.2%), AGR (2.9%), WR (2.8%), and SCG (2.7%). (However, if SCG’s recent election to deduct the costs of the new nuclear units at VC Summer are approved by the IRS, SCG’s residential bill growth rate will drop to 1.5%, while average rate base growth will drop from 8% to 4.5% annually over that period.)

Likely to face the smallest increases in average residential bills, we calculate, are ED (whose average residential bill we estimate must rise by only 0.2% p.a. over 2015-2020), IDA (0.6%), POR (0.7%), OGE (1.1%), SO (1.1%), FE (1.2%) and, notably, HE, in whose service territory the growth of rooftop solar is expected to bring about a decline in average residential bills of 2.2% p.a. over 2015-2020.

Exhibit 12: Expected Annual Increase in Average Residential Customer Bill, 2015-2020, with Sensitivity Analysis

Source: FERC Form 1, SNL, SSR analysis

Exhibit 13: Expected Increase in System Average Bundled Rate, 2015-2020, with Sensitivity Analysis

Source: FERC Form 1, SNL, SSR analysis

Exhibit 14 ranks the publicly traded investor owned utilities into quintiles based on forecast rate base growth over 2015-2020 as well as on the impact of this rate base growth on the average system bundled rate and the average residential bill. EXC and PCG combine first quintile growth in rate base over 2015-2020 with relatively low annual increases in average residential bills. At both companies, residential bill increases over 2015-2020 are expected to fall in the second lowest quintile among their predominantly regulated peers. Also attractive on this basis may be AEP and EIX, which combine second quintile growth in rate base over 2015-2020 with average (middle quintile) increases in residential bills over the same period.

ETR also appears to be in an advantageous situation, enjoying second quintile rate base growth on while facing rates of increase in its average system rate and average residential bill that fall in the lowest and second lowest quintiles, respectively. However, the company recently disclosed $1.4 billion of additional O&M and capex required to improve the performance of the nuclear fleet. If regulators allow full recovery of these expenditures, the rate of increase in ETR’s average residential bill would accelerate from 1.8% to 2.1% p.a., pushing the increase in customer bills into the third quintile. There is also a risk that some portion of these increased expenditures may be disallowed.

Exhibit 14: Regulated Electric Utilities Ranked by Rate Base Growth Prospects and Expected Impact on Average Rates and Bills

Source: FERC Form 1, SNL, SSR analysis

Our relatively optimistic assessment of the impact of future rate base growth on average system rates and customer bills is at risk should utilities’ cost of fuel and purchased power significantly increase, in particular as a result of higher prices for natural gas. In Exhibit 15 we look at the price of natural gas and the historical fuel and purchased power expenses of the utilities, both in nominal terms and as a percentage of revenues, indexed to their levels in 2000. There is a clear relationship, reflecting the growing role of natural gas as a fuel for utilities and unregulated generation. Given that the forward prices for natural gas on the NYMEX market are flat to down, this historical relationship would suggest that fuel and purchased power expense should remain relatively stable.

Exhibit 15: Fuel and Purchased Power Expense of U.S. Investor Owned Electric Utilities Compared to Historical and Forward Prices for Natural Gas (Henry Hub)

Source: FERC Form 1, SNL, SSR analysis

We analyzed the subject further to reflect the different risks for vertically integrated utilities who are primarily purchasing fuel and generating their own power and for utilities that operate in states where generation has been deregulated, and hence are not vertically integrated but rather deliver electricity generated by others (“T&D utilities”). For vertically integrated utilities, we calculate that the impact on average residential bills of an increase in natural gas prices will be limited (see Exhibit 16), reflecting the fuel diversity of these companies’ generating fleets. The utilities that would face the greatest upward pressure on their average residential bills in the event of increase in the price of natural gas would be T&D utilities (see Exhibit 17). Because wholesale prices in these states reflect the variable operating cost of the last generating unit dispatched to meet demand, and in most regions gas fired generators are on or near the margin, an increase in the price of natural gas has a larger impact on the price of purchased power than it does on the fuel cost of a diversified, regulated fleet.

We note, however, that in all states fuel and power costs are now a pass-through to customer bills. Thus, while an increase in the gas price could put upward pressure on customer bills, from a regulatory standpoint it would have no bearing on the rate cases in which utilities seek to recover the capital and O&M costs associated with rate base growth, so risks to earnings growth should be limited even for T&D utilities.

Exhibit 16: Impact on the Retail Electricity Rates of the Vertically Integrated Utilities of a $0.50/MMBTU Increase in the Price of Natural Gas (1)


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1. Reflects the impact of a $0.50/MMBTU move in the price of natural gas at Henry Hub on the average retail electricity rate of the vertically integrated, regulated utility subsidiaries of the companies listed.

Source: Energy Information Administration, FERC Form 1, SNL, SSR analysis

Exhibit 17: Impact on Retail Electricity Rates of a $5.00/MWh Increase in the Wholesale Price of Power

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1. Reflects the impact of a movement in wholesale power prices on the bundled retail electricity rates of the regulated utility subsidiaries of the companies listed that lack generation and deliver to their customers electricity supplied by third parties.

Source: Energy Information Administration, FERC Form 1, SNL, SSR analysis

©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. 1) Utilities are allowed to recover their income tax expense in rates. Because deferred taxes arise when income taxes are expensed but not paid, regulators generally do not allow the utility also to earn a return on its deferred taxes.
  2. 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.
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