The Challenge of Limiting Rate Increases in the Face of Rate Base Growth and Rising Costs: An Analysis of Capex, Opex and Their Impact on Customer Costs

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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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July 31, 2018

The Challenge of Limiting Rate Increases in the Face of Rate Base Growth and Rising Costs:

An Analysis of Capex, Opex and Their Impact on Customer Costs

From 2006 through 2016, U.S. investor owned utilities doubled electric plant in service, while limiting the increase in their aggregate revenue to just 10% over the decade as the cost of fuel and purchased power dropped by 30%. In the absence of a further reduction in energy costs, we expect utilities’ revenue requirement to rise much more rapidly in the years ahead. We test the hypothesis, often put forward by utility managements, that operating cost cuts achieved as a result of utility capex can offset the increase in revenue required to recover the growth in their invested capital. Finding little evidence to support this assertion, we see the industry requiring 2.3% annual increases in revenue per customer over the next five years – after rate cuts from the recent reduction in corporate income tax rates — equivalent to over 4x the rate of increase in revenues per customer over 2006-2016.

  • The ten years from 2006-2016 saw rate base grow at 6.7% p.a. among U.S. investor-owned electric utilities, driven by 7.2 % average annual growth of net electric plant in service – over twice the rate of growth in nominal (current dollar) GDP, which averaged 3.1% p.a. over the decade.
  • By contrast, over 2006-2016 the aggregate revenue of investor-owned electric utilities increased by only 1.0% p.a. On a per customer basis, the aggregate electric revenue of investor-owned utilities increased by only 0.5% p.a., well below the rate of consumer price inflation, which averaged 1.8% p.a. over the period.
  • To explain why such a small revenue increase was sufficient, it is important to understand how the various components of utility industry costs contribute to the revenue requirement of the industry.
    • First, the contribution of net plant in service to utilities’ revenue requirement is fairly limited, comprising depreciation expense plus the pre-tax return on invested capital. These accounted for ~25% of total costs, on average, over 2006-2016. Thus the 7.2% average annual increase in net electric plant over 2006-2016 drove an ~1.8% annual increase in required revenue (25% x 7.2%).
    • Adding to the pressure on the industry’s revenue requirement was a 3.0% average annual increase in non-fuel operation and maintenance (O&M) expense. On average over 2006-2016, O&M expense accounted for ~25% of the electric utility industry’s required revenue. The 3.0% annual growth in these costs thus required a further 0.75% (3.0% p.a. x 25%) average annual increase in electricity revenues, bringing the total required revenue increase to ~2.6% p.a.
  • This upward pressures on utilities’ revenue requirement was offset, however, by a 3.5% annual decrease over 2006-2016 in the industry’s cost of fuel and purchased power. With fuel and purchased power making up ~45% of the industry’s aggregate revenue requirement, these savings reduced required electric utility revenues by ~1.6% annually (3.5% p.a. x 45%).
  • The industry’s outlook for the next five years is less benign. Based on utilities’ announced capex plans, we expect growth in net electric plant in service to average 5.9% p.a. Unlike the last decade, however, currently prevailing forward price curves for natural gas, coal and wholesale power suggest that fuel and purchase power costs will remain broadly flat. The revenue per customer of the investor-owned utilities, we estimate, will need to expand at ~2.3% p.a., over 4x the 0.5% annual increase seen over 2006-2016.
  • Aware that industry costs are likely to follow a less benign trajectory in the coming years, utility management teams have increasingly focused on the opportunity to create “headroom” for rate base growth not by raising revenue but by carving out costs. In this context, utilities frequently cite the substitution of “steel for fuel” or capital for labor as examples of how this can be achieved.
  • Using utilities’ FERC Form 1 filings, we assess whether there is any empirical evidence that, in aggregate across the industry, capex can materially reduce opex, allowing growth in net plant in service to continue without putting upward pressure on utilities’ required revenue. The evidence does not support this thesis.
  • The 30% decline in fuel and purchased power costs over 2006-2016 reflected the fall in the price of natural gas, from $6.75/MMBtu in 2006 to $2.50/MMBtu in 2016, and its consequences:
    • a commensurate decline in the price of power in wholesale markets, such as those in California, Texas and the Northeast, where gas was the price-setting fuel; and
    • a massive shift from coal to gas fired generation across the U.S. generating fleet, with gas’ share of total power output rising from 20% in 2016 to 34% by 2016.
    • Unfortunately, with these dramatic changes as a backdrop, the incremental impact of utilities’ investment in more energy efficient generating plant is difficult to quantify.
  • However, regression analysis of non-fuel O&M expense against net utility plant in service for the years from 2006 through 2016 is feasible, and we conducted a series of these. The first compares (i) the ten-year change over 2006-2016 in non-fuel O&M expense per customer, in constant 2017 dollars, to (ii) the ten-year change over 2006-2016 in real net plant in service per customer, again in constant 2017 dollars, at each of the 27 vertically integrated utilities.
  • The resulting regression equations (see Exhibits 8 and 9) find a statistically significant positive correlation between increases in net plant in service and increases in non-fuel O&M expense.
  • Importantly, however, growth in non-fuel O&M expense has lagged the growth of net plant, presumably reflecting productivity gains. Indeed, only those utilities with the most rapid growth in real net plant in service per customer showed increases in real non-fuel O&M expense per customer; for the slower growing utilities, real decreases in O&M expense per customer were the norm.
  • We also ran a second regression, comparing (i) the ten-year CAGR in real (2017$) net electric plant in service with (ii) the ten-year CAGR in real (2017$) non-fuel O&M expense.
  • We found that a 1.0% average annual rate of increase in net electric plant in service drives an increase of ~0.4 to 0.5% p.a. in non-fuel O&M expense (see Exhibits 10 and 11).
  • Neither of these regression analyses supports the hypothesis that investment in electric plant can so reduce non-fuel O&M expense as to offset the impact on the utility’s revenue requirement of the increase in plant in service. On the contrary, the increase in O&M expense attending the increase in plant in service tends to aggravate, rather than mitigate, the required increase in the utility’s revenue requirement.
  • We conclude that:
  • With declining energy prices no longer providing an offset to the cost of rate base growth, over the next five years, the electric utility industry will likely require ~2.3% annual increases in electric revenue per customer to cover its costs, over 4x the 0.5% annual increase required over 2006-2016.
  • Cost pressures now skew to the upside. With long term interest rates expected to rise, utilities will face higher borrowing costs and will seek higher allowed ROEs. The cost of steel and aluminum, key industry inputs, have increased by ~30% and 10% respectively due to recent tariffs. And a tight jobs market is pushing labor costs higher.
  • Productivity enhancing capex is not a panacea; over 2006-2016, every 1.0% increase in net electric plant in service has been associated with an increase of ~0.4 to 0.5% p.a. in non-fuel O&M expense.
  • In identifying those utilities with the best growth prospects in the industry, therefore, investors will need to consider not only the opportunities for a utility to increase its invested capital, but also its ability to calibrate rate base growth against the impact on retail customer bills. Critical, therefore, will be management’s ability to control input and operating costs, to realize productivity enhancing investments, and to maximize the return on invested capital. This will tend to favor:
  • Utility management teams with a historical track record of controlling O&M costs (e.g., NEE and AEP on our preferred utilities list);
  • Utilities with low electricity rates (e.g., FE and NEE) or excellent regulatory relationships (NEE);
  • Utilities with ample scope for higher-return FERC regulated investments (e.g., AEP and FE), maximizing the earnings contribution of rate base growth;
  • Utilities with the potential to acquire other utilities (or be acquired by them) as a means of achieving large-scale operational efficiencies (e.g., NEE and FE, respectively).

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

Source: SSR analysis

Details

The Golden Age of U.S. Electric Utilities: 2006-2016

Over the ten years from 2006 through 2016, the retail electricity sales of U.S. investor-owned utilities failed to grow. Customer growth was modest, at 0.5% p.a. Yet the decade was also one of remarkable growth for the investor-owned electric utilities, which increased net electric plant in service at an average annual rate of 7.2%.[1] By 2016, net electric plant in service at the U.S. investor owned utilities was double what it had been in 2006 (see Exhibit 2).

Exhibit 2: Growth in Net Electric Plant in Service and O&M Costs vs. Growth in Retail Electricity Sales and Retail Electricity Customers (2006 = 100)

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Source: FERC Form 1, SNL, SSR analysis

It is counter-intuitive that, faced with a stagnant market for electricity, regulated utilities could achieve 7.2% compound annual growth in net utility plant (see Exhibit 3). It is perhaps even more surprising that a 125-year old industry was able to grow 7.2% annually over a decade when the economy as a whole was expanding at only 3.1% p.a. (nominal GDP growth from 2006 through 2016). We have written extensively as to why this was possible and could continue.[2] Our focus here, however, is to analyze the impact of this growth on utilities’ aggregate revenue requirement (see Exhibits 4 and 5), and to assess whether the industry can sustain similar growth in future without putting untenable upward pressure on average electricity rates and average customer bills.

Exhibit 3: Compound Annual Growth in Net Electric Plant by Category Compared to Growth in Retail Electricity Sales and Retail Electricity Customers, 2006-2016

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Source: FERC Form 1, SNL, SSR analysis

As can be seen in Exhibit 4, the doubling of net electric plant in service achieved by the U.S. investor owned utilities from 2006 through 2016 was reflected in only a 10% increase in the electric revenue requirement of the private utility industry, equivalent to an average annual increase in retail electricity revenues of only 1.0%. Offset by 0.5% average annual growth in retail electricity customers over the same period, this translated into an 0.5% annual increase in electricity revenues per customer – well below the rate of increase in the consumer price index, which averaged 1.8% annually over the same period (see (Exhibit 5).

Exhibit 4: Net Electric Plant in Service, Non-Fuel O&M Expense and Fuel and Purchased Power Costs of the U.S. Investor Owned Electric Utilities (2016 = 100)

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Source: FERC Form 1, SNL, SSR analysis

Exhibit 5: 10-Year CAGR in Net Electric Plant, Non-Fuel O&M Expense, Cost of Fuel & Purchased Power, Retail Revenues, MWh Sales, Number of Customers & CPI (2006-2016)

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Source: FERC Form 1, SNL, SSR analysis

To explain how this was achieved, it is helpful to break down the aggregate revenue requirement of the U.S. investor owned electric utility industry into its various cost components. The contribution of net plant in service to these costs is relatively small: over the years 2006-2016, the return of and on utilities’ invested capital (depreciation expense, interest expense and return on equity) accounted for ~25% of the aggregate revenue requirement of the industry. All else being equal, therefore, the 7.2% average annual increase in net electric plant in service over 2006-2016 would be expected to drive an ~1.8% average annual increase in the revenue requirement of the industry (7.2% p.a. x 25%).

Putting further upward pressure on the industry’s revenue requirement as the 3.0% average annual increase in non-fuel operation and maintenance (O&M) expense (Exhibit 5). On average over 2006-2016, non-fuel O&M expense accounted for ~25% of the electric utility industry’s aggregate revenue requirement. The 3.0% annual growth in the costs thus drove a need for a further 0.75% average annual increase in electricity revenues (3.0% p.a. x 25%).

These upward pressures on utilities’ revenue requirement were offset, however, by the 3.5% average annual decrease over 2006-2016 in the industry’s cost of fuel and purchased power, reflecting both the marked drop in the price of natural gas over this period and the consequent shift in generation from coal to gas fired power plants. On average, fuel and purchased power made up ~45% of the industry’s aggregate revenue requirement over 2006-2016. The 3.0% annual decline in these costs would thus have reduced required electric utility revenues by 1.6% annually (3.5% p.a. x 45%).

To compensate for the changes in these three principal cost categories, therefore, the aggregate revenues of U.S. investor owned utilities needed to rise by ~1.0% p.a. over the 2006-2016 (1.8% p.a. for fuel plus 0.75% p.a. for non-fuel operation and maintenance expense less 1.6% p.a. due to the falling cost of fuel and purchased power). Offset by 0.5% average annual growth in retail electricity customers over the same period, this translated into an 0.5% annual increase in electricity revenues per customer.

Over the period 2006-2016, therefore, the breakdown of utility industry costs, and the relative trajectory of these costs, permitted a doubling of net plant service while limiting the increase in electricity revenues per customer to a rate well below that of consumer price inflation. The industry’s outlook for the next five years is less benign.

The Outlook for Growth in Electricity Plant and Required Revenues Over 2017-2021

To estimate the trajectory of utility revenues going forward, we must update our estimates of the contribution of the different categories of industry costs to the revenue requirement of the industry. We do this in Exhibit 6. The left-hand chart presents a breakdown of utility industry costs based upon the 2017 FERC Form 1 filings of U.S. investor owned utilities, while the right-hand chart adjusts this breakdown to reflect the lower corporate tax rate prevailing in 2018. The cut in the corporate tax rate from 35% to 21% is reflected in a corresponding reduction in the pre-tax return on equity allowed electric utilities by their regulators, reducing the aggregate revenue requirement of investor-owned utilities and slightly decreasing the weight of utilities’ return on invested capital in total industry costs.

Exhibit 6: Approximate Breakdown of the Aggregate Revenue Requirement of the U.S. Investor Owned Electric Utilities, by Category of Cost

2017 2018 Est.

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Source: FERC Form 1, SNL, SSR analysis

Next, we need to estimate the likely trajectory of these key industry cost components:

  • Plant in service. Growth in net plant in service is expected to continue, albeit at a slower pace; based on the disclosed capital expenditure plans of publicly traded electric utilities, we expect net electric plant in service to grow at a compound annual rate of ~5.9% over the next five years.
  • Non-fuel O&M expense. Over 2006-2016, non-fuel O&M expense at the investor owned utilities increased at 3.0% p.a., or ~40% of the rate of growth in net plant in service (7.2% p.a.). Were this ratio to persist, 5.9% forecast annual growth in net plant in service would imply growth in non-fuel O&M expense of ~2.4% p.a. going forward.
  • Fuel & purchased power. Forward price curves suggest that the prices of natural gas, coal and wholesale power will be broadly similar in five years’ time to what they are today; if so, utilities’ aggregate cost of fuel and purchased power would also remain broadly unchanged.
  • Other costs. A final contributor to the revenue requirement of the industry is the recovery of net regulatory assets. We assume that this will remain roughly constant over the next five years.

Weighting the expected growth of net electric plant in service (5.9% p.a.) by its contribution to the aggregate revenue requirement of the industry in 2018 (35%, including both depreciation and return on invested capital), would suggest a need for an ~2.1% annual increase in electricity revenues. Similarly, weighting the expected increase in non-fuel O&M expense (2.4% p.a.) by its contribution to revenues (28%) would suggest a need for a further ~0.7% annual revenue increase. Summed together, and assuming other cost categories remain roughly flat, this would suggest that the electric utility industry will require ~2.8% average annual revenue growth to cover expected cost increases over the next five years.

This is not an overly daunting prospect. Given the ~0.5% average annual rate of growth in retail electricity customers, utilities would need to secure from their regulators average annual increases in retail electricity revenues per customer of ~2.3% p.a., or slightly above inflation expectations of ~2.0% p.a. over the next five years (as implied by the difference in yield between five-year U.S. Treasury notes and five-year TIPS).

Nonetheless, such a trajectory in the required revenue of the electric utility industry over the next five years would require utilities to secure from their regulators increases in electric revenue per customer at over 4x the rate they did over 2006-2016 (~2.3% p.a. vs. 0.5% annual increases historically). Various factors, moreover, could drive industry costs higher and contribute to an acceleration of required revenue increases. Long term interest rates are expected to rise as the Federal Reserve raises short term interest rates and the supply of Treasury bonds is increased by the Fed’s unwinding of its bond portfolio and the federal government’s higher borrowing requirement following the 2017 tax cut. Higher long-term interest rates could require utilities to seek revenue relief for rising borrowing costs and increases in their allowed ROEs. Labor costs, which were held in check by persistently high unemployment in the years following the 2008-09 recession, are now coming under upward pressure. Finally, the cost of two key inputs, steel and aluminum, have increased by ~30% and 10%, respectively, as a result of recently imposed tariffs.

Aware that industry costs are likely to follow a less benign trajectory in the coming years than they have over the prior decade, utility management teams have increasingly focused on the opportunity to create “headroom” for rate base growth not by raising revenue but by carving out costs. In this context, utilities frequently cite the substitution of “steel for fuel” or capital for labor as examples of how this can be achieved. One very successful case of the substitution of steel for fuel was Florida Power & Light’s addition of ~3 GW of new combined cycle gas turbine capacity with no net impact on its revenue requirement; the return of and on the capital invested in the new plants was more than offset by the net reduction in fuel costs achieved by retiring 3 GW of oil fired steam turbine capacity with substantially higher heat rates and much higher per Btu cost of fuel. Other utilities have sought to achieve similar fuel cost savings, while adding to net plant in service, by proposing wind farms as a substitute for fossil fuel generation. Others are procuring grid scale energy storage in combination with renewable generation as a means of reducing the cost of energy procured during peak demand hours. Transmission and distribution utilities have pursued similar strategies. Advanced metering infrastructure has been deployed to non-fuel O&M costs by reducing the number of meter readers, selling their vehicles and cancelling their dog bite insurance. Smart grid technologies designed to monitor critical grid components for impending failure are similarly touted as means to substitute technology for costly manual inspections. In each of these examples, the suggestion is that, if properly engineered, capital expenditures can pay for themselves through offsetting reductions in fuel, purchased power or operation and maintenance expense.

How plausible is this suggestion? As we have seen, over 2006-2016 the electric utility industry experienced rapid growth in net plant in service as well as in non-fuel O&M costs. What light can the industry’s experience over this period shed on the question of how to create the headroom for future rate base growth? Is there any empirical evidence that capex can materially reduce opex, allowing growth in net plant in service to continue without putting upward pressure on utilities’ revenue requirement?

Statistical Analysis of Utility Cost Data

Sometimes it can be helpful to frame a statistical analysis by quickly recapping the most salient facts. As set out at the beginning of this note, a decade of investment by U.S. electric utilities over 2006-2016 doubled net utility plant and was associated with a one third decline in the cost of fuel and purchased power and a one third increase in non-fuel O&M expense (see Exhibit 7).

Exhibit 7: Per Customer Net Electric Plant in Service, Non-Fuel O&M Expense and Fuel & Purchased Power Costs of the U.S. Investor Owned Utilities (2016 = 100)

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Source: FERC Form 1, SNL, SSR analysis

The primary driver of the decrease in the cost of fuel and purchased power was of course the drop in the price of natural gas, from an average of $6.75/MMBtu in 2006 to $2.50/MMBtu in 2016. This affected not only the cost of fuel burned in utilities’ gas fired power plants but also the cost of power purchased in wholesale markets, such as those in California, Texas and the Northeast, where gas is the price-setting fuel. The decline in the price of gas was also reflected in a massive shift from coal to gas fired generation across the U.S. generating fleet, with gas’ share of total power output rising from 20% in 2016 to 34% by 2016. Unfortunately, with these dramatic changes as a backdrop, the incremental impact of utilities’ investment in more energy efficient generating plant is difficult to quantify.

Utilities’ non-fuel O&M expense, which is less affected by commodity price movements, continued to rise over the decade, although at a far slower pace (3.0% p.a.) than the growth in net utility plant (7.2% p.a.). It is intuitive that the more generation, transmission and distribution assets utilities place in service the more it will cost to operate and maintain them. On the other hand, the fact that the rate of increase in non-fuel O&M expense was only 40% of that in net plant in service suggest that utilities achieved meaningful operating efficiencies over the decade.

To assess statistically the strength of the relationship between net electric plant in service and non-fuel O&M costs, we have gathered FERC Form 1 financial data on all the investor owned electric utilities in the United States. We smoothed this data by calculating three year running averages of each utility’s net electric plant in service and non-fuel O&M expense. To normalize the data for customer growth, we calculated each utility’s net electric plant in service and non-fuel O&M expense on a per customer basis. Finally, to eliminate the impact of inflation, we expressed both plant in service and non-fuel O&M expense in constant 2017 dollars using industry-specific PPI indices.

Focusing on the 27 vertically integrated utilities of the group, we conducted a series of regression analyses of non-fuel O&M expense against net utility plant in service for the years from 2006 through 2016. The first of these compares (i) the ten-year change over 2006-2016 in non-fuel O&M expense per customer, in constant 2017 dollars, to (ii) the ten-year change over 2006-2016 in real net plant in service per customer, again in constant 2017 dollars, at each of the 27 vertically integrated utilities. This regression analysis produced a positively sloped linear equation, with a good fit to the data (r-squared = 61%) and statistically significant t-statistics for both coefficient and intercept (6.3 and -5.9, respectively) (see Exhibit 8). We then eliminated two outlier data points (those for ALLETE and Hawaiian Electric) and re-ran the regression. The result was again a positively sloped linear equation with an r-squared of 42% and statistically significant t-statistics for both coefficient and intercept (4.1 and -4.2, respectively) (see Exhibit 9).

Exhibit 8: Vertically Integrated Utilities: Exhibit 9: Vertically Integrated Utilities:

10-Year Change in Net Electric Plant in 10-Year Change in Net Electric Plant in Service vs. 10-Year Change in Non-Fuel Service vs. 10-Year Change in Non-Fuel

Electric O&M Costs, 2006-2016 Electric O&M, Excluding Outliers, 2006-2016

(Constant 2017$ per Customer) (1) (Constant 2017$ per Customer) (1)

 

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1. Both net electric plant in service and non-fuel electric O&M costs are calculated on a per customer basis and expressed in constant 2017 dollars using industry-specific PPI indices to eliminate the impact of inflation and customer growth. Exhibit 9 excludes the outliers ALE and HE.

The equations in Exhibits 8 and 9 account for ~40% to 60% of the variation in non-fuel O&M expense. The statistically significant positive coefficient of these two equations confirm that increases in net plant in service are positively correlated with increases in non-fuel O&M expense. The statistically significant negative intercept, however, highlights how the growth in non-fuel O&M expense has lagged the growth of net plant in service, presumably reflecting productivity gains.

In particular, note how in Exhibits 8 and 9 only those utilities with the most rapid growth in real net plant in service per customer showed increases in real non-fuel O&M expense per customer; for the slower growing utilities, decreases in O&M expense per customer were the norm. This would suggest that, in the absence of rapid growth in plant in service, declining real O&M expense per customer would be reducing utilities’ revenue requirement.

One difficulty with the above regression analysis is that the variables are expressed in raw dollars rather than rates of increase, making interpretation of the result more difficult (a $1.00 increase in net plant in service is associated with an $0.08 increase in non-fuel O&M expense – but what does this imply?). We therefore ran a second regression comparing (i) the ten-year CAGR in real (2017$) net electric plant in service with (ii) the ten-year CAGR in real (2017$) non-fuel O&M expense. Across the 27 vertically integrated utilities, this resulted in a positively sloped linear equation with a negative intercept (y = 05249x – 0.0363) with a good fit to the data (r-squared = 65%) and statistically significant t-statistics for both coefficient and intercept (5.5 and -5.7, respectively) (see Exhibit 10). We then eliminated a single outlier (Hawaiian Electric) and re-ran the regression. The result was again a positively sloped linear equation with a negative intercept, an r-squared of 32% and statistically significant t-statistics for both coefficient and intercept (3.4 and -3.5, respectively) (see Exhibit 11).

Exhibit 10: Vertically Integrated Utilities: Exhibit 11: Vertically Integrated Utilities: 10-Year CAGR in Net Electric Plant in 10-Year CAGR in Net Electric Plant in Service Service vs. 10-Year CAGR in Non-Fuel Service vs. 10 Year CAGR in Non-Fuel O&M Costs, 2006-2016 O&M Costs, Excluding Outliers, 2006-2016

(Constant 2017$ per Customer) (1) (Constant 2017$ per Customer) (1)

 

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1. Both net electric plant in service and non-fuel electric O&M cost are calculated on a per customer basis and expressed in constant 2017 dollars using industry-specific PPI indices to eliminate the impact of inflation and customer growth. Exhibit 11 excludes the outlier HE.

These two equations are easier to interpret. The equation in Exhibit 10 suggests that 1.0% average annual rate of increase in net electric plant in service drives an increase of ~0.5% p.a. in non-fuel O&M expense, while the equation in Exhibit 11 suggest that a 1.0% average annual increase in plant in service drives an ~0.4% p.a. increase in non-fuel O&M. Neither equation supports the hypothesis that, in aggregate, investment in electric plant can so reduce non-fuel O&M expense as to fully offset the impact on the utility’s revenue requirement of the increase in plant in service. On the contrary, the increase in O&M expense attending the increase in plant in service serves to aggravate, rather than mitigate, the required increase in the utility’s revenue requirement.

Investment Conclusion

In identifying those utilities with the best growth prospects in the industry, therefore, investors will need to consider not only the opportunities for a utility to increase its invested capital, but also its ability to calibrate rate base growth against the impact on retail customer bills. This will tend to favor:

  • Utility management teams with a historical track record of controlling O&M costs (e.g., NEE and AEP on our preferred utilities list);
  • Utilities with low electricity rates (e.g., FE and NEE) or excellent regulatory relationships (NEE);
  • Utilities with ample scope for higher-return FERC regulated investments (e.g., AEP and FE), maximizing the earnings contribution of rate base growth;
  • Utilities with the potential to acquire other utilities (or be acquired by them) as a means of achieving large-scale operational efficiencies (e.g., NEE and FE, respectively).

©2018, SSR LLC, 225 High Ridge Road, Stamford, CT 06905. All rights reserved. The information contained in this report has been obtained from sources believed to be reliable, and its accuracy and completeness is not guaranteed. No representation or warranty, express or implied, is made as to the fairness, accuracy, completeness or correctness of the information and opinions contained herein.  The views and other information provided are subject to change without notice.  This report is issued without regard to the specific investment objectives, financial situation or particular needs of any specific recipient and is not construed as a solicitation or an offer to buy or sell any securities or related financial instruments. Past performance is not necessarily a guide to future results.

  1. Growth in electric plant rate base over 2006-2016 averaged 6.7% p.a. During this period, the tax code allowed utilities to book bonus depreciation of 50% from 2008 on (100% in 2011), resulting in the accumulation of large deferred tax liabilities. As utility regulators deduct deferred tax liabilities from net utility plant in the calculation of rate base, the accumulation of these deferred tax liabilities acted as a headwind to rate base growth. 
  2. See, for example, our note of October 2, 2017, If This Is the Golden Age of Electric Utilities, What’s Next? Or, How Fast Can Rate Base Grow in the Long Term and on What Will Utilities Spend?. In broad terms, two principal factors contribute to the electric utility industry’s capacity to grow net plant in service at rates well in excess of electricity demand. The first of these is the very long useful life of utility assets, ranging from 20 to 40 years. Even at very low rates of inflation, the replacement cost of these assets will significantly exceed the cost at which they were originally procured 20 to 40 years ago. Reflecting this increase in cost, electric utilities’ capital expenditures to maintain and replace existing plant tend to significantly exceed depreciation expense, resulting, in aggregate across the industry, in positive net capex and continuously rising net plant in service — even in the absence of growth in customers or electricity demand. Second, much of utility capex over the last decade has focused not on increasing the supply of electricity but on upgrading the quality of electricity supplied. Largely, this was in response to changes in federal and state policy priorities and regulatory mandates. For example, over the decade from 2006 through 2016 utility generating fleets faced increasingly stringent federal air regulations governing emissions of SO2, NOx, mercury and particulate matter; the cost to upgrade coal and oil-fired power plants with the necessary controls, and to replace those units where this was uneconomic with lower emitting gas turbine generators, contributed much of utilities’ generation capex over this period without adding to net power output. The same could be said of utility investment in renewable generation to comply with state renewable portfolio mandates, which suppressed the output of CO2-emitting fossil fuel power plants but did not increase the net amount of electricity supplied. Similarly, distribution companies invested over this period in advanced metering systems and smart grid technology designed in large part to reduce the frequency and duration of distribution system outages, rather than to increase deliveries of electricity. Transmission investment surged after the 2003 power blackout, which exposed the fragility of the existing system, and in response to FERC incentives to promote the integration of power grids across newly created regional transmission organizations. Here the policy objectives were both to enhance reliability and to integrate regional wholesale power markets, so as to enable customer access to the lowest cost sources of generation. 
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