Which Utilities Are Best Positioned for Rate Base Growth? How the Cost Structure of Utilities Can Benefit or Constrain Growth in Rate Base

gcopley
Print Friendly
Share on LinkedIn0Tweet about this on Twitter0Share on Facebook0

______________________________________________________________________________

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

______________________________________________________________________________

September 6, 2018

Which Utilities Are Best Positioned for Rate Base Growth?

How the Cost Structure of Utilities Can Benefit or Constrain Growth in Rate Base

In this note, we analyze how the different cost structures of vertically integrated and transmission and distribution utilities, and of the individual utilities within these two groups, affect their ability to secure the revenue increases required to sustain rate base growth. In our next research report, we will use the most recent regulatory filings of the publicly traded utilities, and their announced capex plans, to update our estimates of their growth in rate base over the next five years. We will then assess how this rate base growth will affect customer bills, and thus regulatory support for or opposition to utilities’ planned capex.

  • The return of and on invested capital (i.e., depreciation expense, interest expense and pre-tax return on equity, or EBITDA) comprises a far larger share of the revenue requirement of vertically integrated utilities (39%) than it does of the revenue of T&D utilities (25%), reflecting the ownership of generation plant by the former group and the reliance on purchased power by the latter. The implication is that a 1% increase in rate base at the vertically integrated utilities will drive a materially higher increase in required revenue (0.39%) than at the T&D companies (0.25%). (See Exhibit 6).
  • Similarly, because vertically integrated utilities own generating fleets to supply the electricity required by their customers, while T&D utilities do not, non-fuel operation and maintenance expense is also a larger component of revenues at the vertically integrated utilities (28%) than at the T&D companies (19%) (Exhibit 6). This is significant because our historical analysis has found that, over long periods of time, increases in non-fuel O&M expense show a strong positive correlation with the growth of net plant in service, which in turn is the primary driver of rate base growth (Exhibits 7 & 8).
  • Rate base growth will thus put upward pressure on two key components of utilities’ cost of service, the return of and on invested capital and non-fuel O&M expense. These two cost components account for 67% of the revenue requirement of the vertically integrated utilities. At the T&D utilities, by contrast, the corresponding proportion is only 44%.
  • These comparisons suggest that, for every dollar increase in rate base, vertically integrated utilities require ~1.5x the increase in regulated revenues that T&D utilities do. Resistance to rate increases is thus likely to be a more significant constraint on the growth of vertically integrated utilities than will be the case for T&D companies.
  • The contrasting cost structures of vertically integrated and T&D utilities has a corollary, however, that is less advantageous for the latter group: the cost of fuel and purchased power, the portion of expenses over which utility managements have the least control, represents a far larger share of regulated revenues at the T&D utilities (56%) than at the vertically integrated utilities (33%) (Exhibit 6). For all utilities, movements in the prices of fuel and purchased power cause unpredictable headwinds or tailwinds to rate base growth; customers must pay for the pass-through of power supply costs, constraining their ability to absorb the revenue increases required to sustain rate base growth. T&D utilities find themselves particularly vulnerable, however; on average, increases in the prices of fuel and purchased power require revenue increases that are some 70% larger at T&D utilities than at their vertically integrated counterparts.
  • In summary, rate base growth is a far more important driver of increases in the required revenue of the vertically integrated utilities than at the T&D utilities. Conversely, customer bills at the T&D utilities are far more sensitive to movements in the prices of fuel and wholesale power than are customer bills at the vertically integrated utilities. While T&D utilities should thus be better positioned to recover the costs associated with rate base growth, their ability to do so is much more contingent on the trajectory of fuel and purchased power costs.
  • If they are to be effective as predictors of the revenue increases required to sustain rate base growth, the ratios of EBITDA to revenues and non-fuel O&M expense to revenues must be relatively stable over time and not prone to change from year to year. To test this proposition, we have compiled long term quintile rankings of the electric utilities based on these ratios. As can be seen in Exhibits 11 through 14, it is unusual for a utility to occupy any given quintile ranking for just one year at a time; it is more common, rather, for a utility maintain its quintile ranking for three years or longer, with quintile rankings often persisting for five to ten years. This suggests that these ratios are likely to be effective predictors of the revenue increases required to sustain rate base growth.
  • On this basis, which utilities are best positioned to secure the revenue increases they need?
    • The publicly traded utilities with the lowest ratios of EBITDA to revenue are HE, ETR and WEC among the vertically integrated utilities, and EXC, AGR, FE and PPL among the T&D utilities. (See Exhibits 15 and 16).
    • The utilities with the highest ratios of EBITDA to revenue are D, SCG and NEE, among the vertically integrated utilities, and EIX and PCG among the T&D utilities.
  • Given the historical correlation between growth in net electric plant in service – the primary driver of rate base growth – and non-fuel electric O&M expense, the latter must also be considered in assessing the sensitivity of utilities’ revenue requirement to rate base growth.
    • The publicly traded utilities with the lowest ratios of EBITDA plus non-fuel O&M expense to revenue are HE, ETR and ALE among the vertically integrated utilities, and FE, PPL and EXC among the T&D utilities. (See Exhibits 17 and 18).
      • NEE, which had been among the vertically integrated utilities with the highest ratio of EBITDA to revenues, has a below average ratio of EBITDA plus O&M expense to revenue, whereas WEC, which has one of the lowest EBITDA to revenues ratios, has an above average ratio of EBITDA plus O&M expense to revenue.
      • Among T&D companies, AGR’s substantially below average ratio of EBITDA to revenue becomes an above average ratio when O&M expense is added to EBITDA.
    • The publicly traded utilities with the highest ratios of EBITDA plus non-fuel O&M expense to revenue are PNM, DTE, EVRG and D, among the vertically integrated utilities, and EIX and PCG among the T&D subsidiaries.
  • The corollary to the benefit of low EBITDA and O&M to revenues reducing the impact of rate base growth on rates is that fuel and purchased power, the primary remaining component of required revenues, is a higher percentage and rates are more exposed to changes in fuel and power prices.
    • The publicly traded utilities with the highest ratio of fuel and purchased power to revenue are ETR, ALE and CMS among vertically integrated utilities, and PPL, EXC and FE among the T&D subsidiaries. (See Exhibits 19 and 20).

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

Source: SSR analysis

1. Background

The last fifteen years have been ones of robust and steady growth in the regulated rate base of U.S. utilities. The aggregate electric rate base of U.S. investor owned utilities expanded at a compound annual rate of 6.6% from 2002 through 2017, achieving a cumulative increase of 161% (see Exhibit 2). This rapid growth in rate base has steadily increased the revenue requirement of the regulated utilities, to ensure the recovery of and on capital invested. This upward pressure on customer bills was compounded in the early years of the period by rapidly rising energy costs. From 2002 through 2008, the delivered price of natural gas to U.S. utilities rose from an average of $3.68 to $9.26 per MMBtu and the average price of bituminous coal rose from $27 per short ton in to $51. The impact of these changes in fuel prices on retail power prices was aggravated in the states that had recently deregulated generation by the transition from average to marginal cost pricing. As a result, from 2002 through 2008 average customer bills at investor owned electric utilities increased by a third, exceeding the increase in the consumer price index by 13.3 percentage points or 180 basis points per annum (see Exhibit 3).

From 2008 through 2017, by contrast, average customer bills began to decline in real terms, lagging the rate of increase in the consumer price index by 7.5 percentage points over the period or 80 basis points per annum. This long decline primarily reflected the sharp drop in the delivered price of natural gas to U.S. utilities, from an average $9.26/MMBtu in 2008 to $3.52/MMBtu in 2017, and the consequent transition from coal fired to gas fired generation, which rose from 21% of U.S. power output in 2008 to 32% in 2017 as gas fired generators undercut their higher cost coal fired competitors (Exhibits 3 and 4). (For a fuller discussion of this history, please see our research report of July 31stThe 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.)

Exhibit 2: Growth in Electric Rate Base, Fuel & Purchased Power Costs and O&M Expense

_________________________________

Source: FERC Form 1, SNL, Bureau of Labor Statistics, SSR analysis

Exhibit 3: Annual Electric Revenue per Customer at U.S. Publicly Traded Utilities, 2002-17

_________________________________

Source: FERC Form 1, SNL, Bureau of Labor Statistics, SSR analysis

Exhibit 4: CAGR in Electric Revenue per Customer at U.S. Publicly Traded Utilities

_________________________________

Source: FERC Form 1, SNL, Bureau of Labor Statistics, SSR analysis

For the U.S. investor owned utilities, the last ten years (2007-2017) have thus represented the halcyon days of the industry, a period when falling costs for fuel and purchased power have allowed the industry to achieve ~6.6% compound annual growth in aggregate electric rate base while limiting the growth in average customer bills to 1.0% p.a.. — substantially below the rate of inflation, which averaged 1.7% p.a. over the period. The industry’s outlook for the next five years, however, is less benign. Based on the announced capex plans of the investor owned utilities, we estimate that customer bills must rise at ~2.3% p.a. – more than twice the rate of the last ten years and above the anticipated rate of inflation of 2.0% implied by the differential in yields between TIPS and Treasury notes.

Our estimate of the future trajectory of average customer bills reflects trends in the key cost components underlying the industry’s revenue requirement. Our estimate of the contribution of each of these cost components to the aggregate revenue requirement of the investor owned utilities is presented in Exhibit 5.

  • Plant in service. 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 2007-2017, non-fuel O&M expense at the investor owned utilities increased at 2.9% 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 ~2.3% 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, although there will be a temporary decline during this period at many utilities as they return excess non-PP&E-related deferred taxes to customers.

Exhibit 5: Approximate Breakdown of the Aggregate Revenue Requirement of the U.S. Investor Owned Electric Utilities, by Category of Cost

2017 2018 Est.

_________________________________

Source: FERC Form 1, SNL, SSR analysis

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; see Exhibit 5), would suggest a need for an ~2.1% annual increase in electricity revenues. Similarly, weighting the expected increase in non-fuel O&M expense (2.3% p.a.) by its estimated contribution to 2018 revenues (28%) would suggest a need for a further ~0.7% annual revenue increase. Summed together, and assuming other cost categories remain roughly flat, we expect the electric utility industry to require ~2.8% average annual revenue growth, and average annual customer bill growth of ~2.3%, to cover expected cost increases over the next five years.

In the sections that follow, we will seek to identify those regulated utilities best positioned to secure the rate increases required to sustain rate base growth in a rising cost environment. We will first consider how the different cost structures of the vertically integrated utilities and transmission and distribution companies render the average customer bills of the former far more sensitive to rate base growth, while the customer bills of T&D utilities are far more sensitive to the cost of purchased power. We will then identify those utilities in each group whose revenue requirements are most sensitive to growth in regulated rate base, and therefore will require the largest increases in customer bills to sustain their planned rate base growth.

2. What are the key drivers of revenue increases at vertically integrated and T&D utilities?

Exhibit 6 breaks down the retail electric revenues of the vertically integrated utilities and T&D companies into the key components of these utilities’ cost of service. As can be seen there, the return of and on invested capital (i.e., depreciation expense, interest expense and pre-tax return on equity) comprise a far larger share of the revenue requirement of vertically integrated utilities (39%) than of the revenues of T&D utilities (25%), reflecting the ownership of generation plant by the former group and the reliance on purchased power by the latter. The implication, of course, is that a 1% increase in rate base at the vertically integrated utilities will drive a materially higher increase in required revenue (0.39%) than at the T&D companies (0.25%).

Exhibit 6: Breakdown of 2017 Retail Electric Revenues into Key Cost Components

Vertically Integrated Utilities Transmission & Distribution Utilities

_________________________________

Source: FERC Form 1, SNL, SSR analysis

Similarly, because vertically integrated utilities own generating fleets to supply the electricity required by their customers while T&D utilities do not, non-fuel operation and maintenance expense is also a materially larger component of revenues at the vertically integrated utilities (28%) than at the T&D companies (19%). This is significant because our historical analysis has found that, over long periods of time, increases in non-fuel O&M expense show a strong positive correlation with the growth of net plant in service, which in turn is the primary driver of rate base growth. Focusing on the 27 vertically integrated utilities, we found that a regression analysis comparing (i) the ten-year change over 2006-2016 in non-fuel O&M expense per customer, expressed 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, produced a positively sloped linear equation, with a good, statistically significant fit to the data (r-squared = 42%) (see Exhibit 7). Similarly, a 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 resulted in a positively sloped linear equation providing a good, statistically significant fit to the data (r-squared = 32%) (see Exhibit 8). For a fuller explanation of our statistical analysis, please see the Appendix to this research report.

Exhibit 7: Vertically Integrated Utilities: Exhibit 8: Vertically Integrated Utilities:

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

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

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

____________________________________

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 7 excludes the outliers ALE and HE, while Exhibit 8 excludes outlier HE.

Source: FERC Form 1, SNL, SSR analysis

If growth in net plant in service can explain 32% to 42% of the long-term growth in non-fuel O&M expense, the implication is that rate base growth will put upward pressure on two key components of utilities’ cost of service, the return of and on capital invested and non-fuel O&M expense. These two cost components account for 67% of the revenue requirement of the vertically integrated utilities (see Exhibit 6). At the T&D utilities, which lack generation plant, the corresponding proportion is only 44%. The corollary, however, is that the cost of fuel and purchased power, the portion of expenses over which management exerts the least control, represents a far larger share of regulated revenues at the T&D utilities (56%) than at the vertically integrated utilities (33%).

The implication of these facts is that rate base growth is a far more important driver of increases in the required revenue of the vertically integrated utilities than at the T&D utilities. Conversely, customer bills at the T&D utilities should be more sensitive to movements in fuel costs and wholesale power prices than is the case for vertically integrated utilities. While T&D utilities should therefore be better positioned to recover the costs associated with rate base growth, their ability to do so would appear to be far more contingent on the trajectory of fuel and purchased power costs than would be true of the vertically integrated utilities.

Exhibit 9 and 10 present additional data that provide an interesting alternative perspective on this issue. As can be seen there, 2008 marked the beginning of a sustained increase among U.S. investor owned utilities in the return of and on invested capital (depreciation, interest expense and pre-tax return on equity, or EBITDA), just as the cost of fuel and purchased power began to turn down. This inverse relationship between the growth of the industry’s aggregate EBITDA (the green lines in in Exhibit 9) and its fuel and purchased power costs (the orange lines) is evident at both the vertically integrated and transmission and distribution utilities, and suggests that management teams across the industry have capitalized on the decline in the cost of fuel and purchased power to accelerate rate base growth. The inverse relationship also suggest that future increases in fuel and purchased power costs, by putting upward pressure on customers’ bills, could cause utilities to reduce their investment plans and slow their rate base growth.

Exhibit 9: Trajectory of the Principal Components of Utilities’ Cost of Service, Expressed on a per Customer Basis (2002 = 100)

Vertically Integrated Utilities Transmission & Distribution Utilities

_________________________________

Source: FERC Form 1, SNL, SSR analysis

Exhibit 10: CAGRs of the Principal Components of Utilities’ Cost of Service, Expressed on a per Customer Basis

Vertically Integrated Utilities Transmission & Distribution Utilities

_________________________________

Source: FERC Form 1, SNL, SSR analysis

Importantly, however, the cost of fuel and purchased power showed a far more substantial decline from 2008 through 2017 at the vertically integrated utilities (-5.0% p.a.) than at the transmission and distribution companies (-0.7% p.a.) – suggesting that fuel and purchased power costs may be more volatile among the vertically integrated utilities than among the T&D utilities. This is explained, we believe, by the fact that the cost of fuel and purchased power at vertically integrated utilities tends primarily to reflect the cost of fuel, whereas at the transmission and distribution utilities it reflects the cost of procuring full-requirements power, whose price includes not only the cost of fuel but also (i) a capacity component to compensate power suppliers for their fixed costs of generation and (ii) the transmission expense of transporting the power procured to the distribution grid.

To the degree that they are load-serving entities, transmission and distribution utilities in many deregulated states are required to procure capacity directly under long term contracts (e.g., California) or to purchase capacity in organized capacity markets (e.g., PJM and the New England ISO). In many deregulated states, utilities also have been required to procure renewable energy under long-term PPAs to comply with state renewable portfolio standards. Because they are designed to cover the fixed costs of generation, the capacity payments under these long-term power purchase agreements tend to be more stable than the cost of fuel. The market price of capacity in wholesale power markets, moreover, has tended to rise as fuel prices have fallen. Also contributing to the relative stability of T&D companies’ cost of fuel and purchased power is the transmission expense these companies incur to wheel purchased power to their service territories. Transmission rates a regulated and relatively stable, largely covering the fixed costs of transmission infrastructure. Over the last decade, moreover, transmission costs have tended to rise as fuel costs have fallen, as investment in transmission plant has grown rapidly. In summary, while the recovery of fuel and purchased power costs accounts for a far larger portion of revenues at transmission and distribution utilities (56%) than at vertically integrated utilities (33%), this category of costs may be more volatile at the vertically integrated utilities, where it reflects primarily the cost of fuel, than at the transmission and distribution utilities, where it reflects the cost of procuring not only wholesale electricity but also generation and transmission capacity.

3. At which utilities will rate base growth have the least impact on rates?

We believe that the ratio of EBITDA to revenues can serve as a measure of the relative ease with which a utility can secure the rate base increases required to sustain its planned rate base growth. EBITDA comprises pre-tax earnings, interest expense and depreciation, and is thus equivalent to the return of and on capital invested. At utilities where the ratio of EBITDA to revenues is high, rate base growth should have a larger impact on the utility’s revenue requirement, and therefore on customer bills, than at utilities where this ratio is low.

A further measure of the degree to which rate base growth may require a substantial increase in a utility’s revenues, and thus in its customers’ bills, is the ratio of EBITDA plus non-fuel O&M expense to revenues. As discussed above, the growth in electric non-fuel O&M expense has historically been correlated with the growth in net electric plant. In this section, therefore, we will rank the electric utilities on their ratios of EBITDA to revenues and EBITDA plus O&M expense to revenues.

Finally, to help investors evaluate the risk to rate base growth from movements in prices of fuel and purchased power, we will also rank the utilities on the ratio of fuel and purchased power costs to revenues.

If the ratios of EBITDA to revenues and EBITDA plus O&M expense to revenues are to be effective as predictors of the revenue increases required to sustain rate base growth, these ratios must be relatively stable over time and not prone to change from year to year. To test this proposition, we have compiled long term quintile ranking of the electric utilities based on these two ratios (see Exhibits 11 through 14). As these charts illustrate, it is unusual for a utility to occupy any given quintile ranking for just one year at a time. It is far more common to see a utility maintain its quintile ranking for three years or longer, with quintile rankings often persisting for five to ten years. This would suggest that the ratios of EBITDA to revenue and non-fuel O&M expense to revenues are likely to be effective predictors of the revenue increases required to sustain rate base growth.

Exhibit 11: Electric EBITDA as a Percentage of Electric Retail Revenues, Quintile Ranking of the Vertically Integrated Utilities, 2002-2017

____________________________

Source: FERC Form 1, SNL, SSR analysis

Exhibit 12: Electric EBITDA as a Percentage of Electric Retail Revenues, Quintile Ranking of the Transmission & Distribution Utilities, 2002-2017

_________________________________

Source: FERC Form 1, SNL, SSR analysis

Exhibit 13: Non-Fuel Electric O&M Expense as a Percentage of Electric Retail Revenues, Quintile Ranking of the Vertically Integrated Utilities, 2002-2017

_________________________________

Source: FERC Form 1, SNL, SSR analysis

Exhibit 14: Non-Fuel Electric O&M Expense as a Percentage of Electric Retail Revenues, Quintile Ranking of the Transmission & Distribution Utilities, 2002-2017

_________________________________

Source: FERC Form 1, SNL, SSR analysis

On the basis of these metrics, then, which utilities are best positioned to secure the revenue increases they need? Exhibit 15 ranks the vertically integrated utilities on their ratio of EBITDA to revenues, and Exhibit 16 does the same for the T&D utilities. The publicly traded utilities with the lowest ratios of EBITDA to revenue are HE, ETR and WEC among the vertically integrated utilities, and EXC, AGR, FE and PPL among the T&D utilities.[1] The utilities with the highest ratios of EBITDA to revenue are D, SCG and NEE, among the vertically integrated utilities, and EIX and PCG among the T&D subsidiaries.

Exhibit 15: Electric EBITDA as a Percentage of Electric Revenues, Vertically Integrated Utilities, 2017

_________________________________

Source: FERC Form 1, SNL, SSR analysis

Exhibit 16: Electric EBITDA as a Percentage of Electric Revenues, Transmission & Distribution Utilities, 2017

_________________________________

Source: FERC Form 1, SNL, SSR analysis

In Exhibits 17 and 18, we rank the vertically integrated utilities and transmission and distribution companies, respectively, on the ratio of EBITDA plus O&M expense to revenues. The publicly traded utilities with the lowest ratios of EBITDA plus non-fuel O&M expense to revenue are HE, ETR and ALE among the vertically integrated utilities, and FE, PPL and EXC among the T&D utilities.[2] The publicly traded utilities with the highest ratios of EBITDA plus non-fuel O&M expense to revenue are PNM, DTE, EVRG and D, among the vertically integrated utilities, and EIX and PCG among the T&D subsidiaries.

The inclusion of non-fuel O&M expense results in meaningful changes in the rankings for a few companies and, therefore, for the potential pressure they will face as rate base grows. NEE, which is among the vertically integrated utilities with the highest ratio of EBITDA to revenue, has a below average ratio of EBITDA plus O&M expense to revenue, whereas WEC, which has one of the lowest EBITDA to revenue ratios, has an above average ratio of EBITDA plus O&M expense to revenue. Among T&D companies, AGR’s substantially below average ratio of EBITDA to revenue becomes an above average ratio when O&M is added to EBITDA.

Exhibit 17: Electric EBITDA Plus Electric Non-Fuel O&M Expense as a Percentage of Electric Revenues, Vertically Integrated Utilities

_________________________________

Source: FERC Form 1, SNL, SSR analysis

Exhibit 18: Electric EBITDA Plus Electric Non-Fuel O&M Expense as a Percentage of Electric Revenues, Transmission and Distribution Utilities

_________________________________

Source: FERC Form 1, SNL, SSR analysis

Relative to the vertically integrated utilities, the T&D companies’ low ratio of EBITDA to revenues would appear to represent an important advantage in securing the revenues required to sustain rapid rate base growth. As we discussed above, however, the corollary risk is the very high ratio of fuel and purchased power costs to revenues at the T&D utilities. As can be seen by comparing Exhibits 19 and 20, the average ratio of fuel and purchased power costs to revenues at the T&D utilities is 69%; at the vertically integrated utilities it is 37%. The lowest such ratio among the T&D utilities is 59%, higher than all but two of the vertically integrated utilities. We have discussed above how the volatility of fuel and purchased power costs tends to be lower at the T&D companies than at the vertically integrated utilities, reflecting the practice among the T&D utilities of contracting for full requirements power on a multi-year basis, and the relatively large share of the purchased power price that goes to cover suppliers’ fixed capacity and transmission costs. Nonetheless, with the bulk of T&D utilities’ retail revenues going to recover the cost of purchased power, the risk that increases in the prices of fuel and wholesale power will put substantial upward pressure on customer bills, and act as a headwind to rate base growth, remains a far more meaningful one at the T&D companies than at the vertically integrated utilities.

The publicly traded utilities with the highest ratios of fuel and purchased power costs to revenue are ETR, ALE, CMS, AEP and NEE, among the vertically integrated utilities (see Exhibit 19) and PPL, EXC and FE among the T&D utilities (see Exhibit 20).[3] The publicly traded utilities with the lowest ratios of fuel and purchased power costs to revenue are EVRG, DTE, PNM, AVA and AEE, among the vertically integrated utilities and AEP, AGR, ED and ES among the T&D utilities.

Exhibit 19: Fuel & Purchased Power Costs as a Percentage of Electric Revenues, Vertically Integrated Utilities

_________________________________

Source: FERC Form 1, SNL, SSR analysis

Exhibit 20: Fuel & Purchased Power Costs as a Percentage of Electric Revenues, Transmission & Distribution Utilities

_________________________________

Source: FERC Form 1, SNL, SSR analysis

Exhibit 21: Fuel & Purchased Power Costs as a Percentage of Electric Revenues, Quintile Ranking of Vertically Integrated Utilities

_________________________________

Source: FERC Form 1, SNL, SSR analysis

Exhibit 22: Fuel & Purchased Power Costs as a Percentage of Electric Revenues, Quintile Ranking of Transmission & Distribution Utilities

_________________________________

Source: FERC Form 1, SNL, SSR analysis

Appendix: The Relationship Between Growth in Non-Fuel O&M Expense and Growth in Net Plant in Service

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 23). 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 24).

Exhibit 23: Vertically Integrated Utilities: Exhibit 24: 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)

____________________________________

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 23 excludes the outliers ALE and HE, while Exhibit 24 excludes the outlier HE.

Source: FERC Form 1, SNL, SSR analysis.

The equations in Exhibits 23 and 24 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 23 and 24 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 25). 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 26).

Exhibit 25: Vertically Integrated Utilities: Exhibit 26: 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)

____________________________________

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 26 excludes the outlier HE.

Source: FERC Form 1, SNL, SSR analysis.

These two equations are easier to interpret. The equation in Exhibit 25 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 26 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.

©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. In Exhibit 15, FE is represented only by its Monongahela Power subsidiary. In Exhibit 16, DUK is represented only by its Duke Energy Ohio subsidiary. 
  2. In Exhibit 17, FE is represented only by its Monongahela Power subsidiary. In Exhibit 18, DUK is represented only by its Duke Energy Ohio subsidiary. 
  3. In Exhibit 19, FE is represented only by its Monongahela Power subsidiary. In Exhibit 20, DUK is represented only by its Duke Energy Ohio subsidiary. 
Print Friendly