How Would the GOP Tax Plan Impact Rate Base Growth?

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Eric Selmon Hugh Wynne

Office: +1-646-843-7200 Office: +1-917-999-8556

Email: eselmon@ssrllc.com Email: hwynne@ssrllc.com

SEE LAST PAGE OF THIS REPORT FOR IMPORTANT DISCLOSURES

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October 10, 2016

How Would the GOP Tax Plan Impact Rate Base Growth?

The tax reform framework released jointly by Republican Congressional leadership and the Trump Administration on September 27 contains three elements that would materially affect utilities: (i) a cut in the maximum federal tax rate on corporate income to 20%, from 35% currently; (ii) a provision allowing corporations to expense rather than capitalize the cost of new investments in depreciable assets; and (iii) a statement that “the deduction for net interest expense incurred by C corporations will be partially limited.” In this note, we assess the impact of these elements on the rate base growth and customer bills of the regulated utilities. We calculate that the combined impact of lower tax rates and the expensing of capex will be to reduce the average of rate base growth among the regulated utilities by ~80 b.p. to 5.8% p.a. over 2018-2021, and by ~50 b.p. to 4.9% over 2021-2025.

Portfolio Manager’s Summary

  • The keystone of the GOP tax plan is a cut in the corporate tax rate to 20% from 35% currently. The impact on utility valuations, however, will be limited: regulated utilities will ultimately be forced to pass through to ratepayers any tax savings that they realize as a result.
  • Only utilities with large, profitable competitive businesses, such as D, EXC, NEE and PEG, should see a permanent improvement in the after-tax earnings of these operations.
  • The loss of the interest deduction would similarly be passed through by regulated utilities to rates, and thus would have no long term impact on earnings. In combination with a cut in the corporate tax rate to 20%, moreover, even the complete elimination of the interest deduction would result in a reduction in regulated utilities’ revenue requirement.
  • Unable to offset the loss of the tax deduction, however, would be primarily regulated utilities with significant holding company debt, such as DUK, and hybrid utilities with debt at the holding company or at competitive subsidiaries, such as D, EXC, FE, NEE and PEG.
  • Most important is the combined impact of the reduction in tax rates and the expensing of capital expenditures on utilities’ deferred taxes and, as a result, on rate base growth. Utilities’ allowed return on rate base, generally defined as utility plant in service less deferred taxes, is the primary driver of regulated utility earnings.
  • We calculate that the combined impact of lower tax rates and the expensing of capex will be to reduce the average rate base growth of the regulated utilities by ~80 b.p. to 5.8% p.a. over 2018-2021, and by ~60 b.p. to 4.9% over 2021-2025 (see Exhibit 1).
  • Among hybrid utilities, the estimated reduction in average rate base growth would be ~90 b.p. to 6.1% over 2018-2021 and ~40 b.p. to 5.1% over 2021-2025 (Exhibit 2).
  • The regulated utilities likely to see the smallest reductions in 2016-2021 rate base growth as a result of the tax plan are ED, ES, HE, OGE, POR and SCG. The largest decreases in rate base growth would likely occur at CMS, DTE, EE, EIX, NWE, and PCG.
    • Among hybrid utilities, EXC and PEG would likely see the smallest reductions in rate base growth, while ETR and NEE would likely suffer the highest (Exhibit 8).
  • The GOP tax plan suggests that the expensing of capex may be limited to five years. If so, the rate base growth of the regulated utilities would accelerate thereafter, relative to that under the current tax code.
    • By expensing in full five years of capital expenditures, utilities would significantly reduce depreciation expense for tax purposes in the years that follow. With book depreciation exceeding tax depreciation, utilities would thus begin to reverse their deferred tax liabilities, boosting rate base growth.
    • As a result, we estimate that average rate base growth among regulated utilities would accelerate by ~60 b.p. to 6.0% p.a. over 2021-2025 (Exhibit 9).
    • Among hybrid utilities, rate base growth over 2021-2025 would rise by ~70 b.p. to 6.2%.
  • Lower rate base, and the pass-through to ratepayers of materially lower tax rates, are expected to reduce electricity rates and bills relative to their anticipated levels under the current tax code.
    • We calculate that the combined impact of reduced rate base and lower tax rates will be to slow the average rate of increase in regulated utilities’ average system rates by ~40 b.p. to 2.5% p.a. over 2016-2021 (Exhibit 11). Growth in average residential bills is expected to fall by ~40 b.p. to 1.5% p.a. over 2016-2021 (Exhibit 12).
    • Among hybrid utilities, the average increase in average system rates is expected to slow by ~50 b.p. to 1.9% p.a. over 2016-2021. Growth in average residential bills is expected to slow by ~40 b.p. to 1.4% p.a.
    • These forecast increases in average system rates are in line with expected inflation, while expected growth in customer bills lags inflation expectations.
  • The regulated utilities likely to see the largest decreases in average system rates as a result of the GOP tax plan are DUK, GXP, PNW, PPL, SO and WR (see the right hand column of Exhibit 11). Likely to see the smallest decreases in average system rates are ED, EIX, IDA, NWE, OGE and PCG.
    • Among the hybrid utilities, D and NEE are likely to enjoy the largest decreases in average system rates due to GOP tax plan, AGR and EXC the smallest.
  • A reduction in tax rates from 35% to 20% would materially reduce the value of the deferred tax liabilities on utilities’ books. Unlike competitive companies, where a reduction in net deferred tax liabilities flows through to comprehensive income, regulated utilities must pass through any reduction in their deferred tax liability to their ratepayers. Ordinarily, this would be done over the remaining useful life of the assets that gave rise to the deferred taxes. However, the return to ratepayers of the reduction in deferred taxes could be accelerated to mitigate the impact on customer bills of rapid rate base growth or other anticipated cost increases.
    • Among the regulated utilities, the largest reduction in deferred tax liabilities as a percentage of retail electric revenues is expected to occur at AEE, ALE, LNT, PNM, PNW, and PPL. The smallest reductions are anticipated at AVA, CMS, HE, IDA, NWE and POR (see Exhibit 10).
    • Among the hybrid utilities, the largest reduction in deferred tax liabilities is expected to occur at EXC and PEG. The smallest reductions are anticipated at AGR and NEE.

Exhibit 1: Average of Rate Base CAGRs of the Primarily Regulated Utilities 

Exhibit 2: Average of Rate Base CAGRs of the Hybrid Utilities


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

Exhibit 3: Average Annual Increase in Average System Rates, 2016-2021 

Exhibit 4: Average Annual Increase in Average Residential Bills, 2016-2021

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

  • We are removing Entergy (ETR) from our list of least favored hybrid utilities. ETR’s nuclear performance, as measured by violations and findings by the Nuclear Regulatory Commission, has improved significantly over the last 12 months. In addition, in ETR’s rate proceeding in Arkansas, the Arkansas PSC staff recommended recovery of the increased nuclear operating costs at Arkansas Nuclear One. Although lower tax rates from tax reform would significantly reduce the value of the accumulated NOLs from their merchant nuclear fleet, and risks remain with respect to the decommissioning of the nuclear fleet, those risks appear to be priced into the stock at this time.

 

Exhibit 5: Heat Map: Preferences Among Utilities, IPP and Clean Technology


Source: SSR analysis

Details

The tax reform framework released jointly by Republican Congressional leadership and the Trump Administration on September 27 contains three elements that would materially affect utilities: (i) a cut in the maximum federal tax rate on corporate income to 20%, from 35% currently; (ii) a provision allowing corporations to expense rather than capitalize the cost of new investments in depreciable assets; and (iii) a statement that “the deduction for net interest expense incurred by C corporations will be partially limited.” In this note, we assess the impact of these elements on the rate base growth and customer bills of the regulated utilities.

Tax Normalization and the Impact of Deferred Taxes on Rate Base Growth

The rate base of a regulated utility is the invested capital on which it is allowed to earn a regulated return. Utilities are allowed to earn a return on their rate base roughly equivalent to the weighted average cost of the debt and equity capital used to fund their investment in property, plant and equipment. Because a utility’s deferred tax liability largely represents income taxes expensed but not yet paid, and thus does not represent an outlay of capital, regulated utilities are not allowed to earn a return on the portion of their net PP&E that is funded by their deferred tax liability. As a result, rate base is generally calculated as the value of a utility’s net property, plant and equipment less the utility’s deferred tax liability. [1]

In 1981, to ensure that the benefit of federal tax incentives for investment were enjoyed and acted upon by regulated utilities, Congress modified the federal tax code to require the use of tax normalization rather than flow through accounting by regulated utilities. Flow through accounting recognizes immediately the reduction in income taxes resulting from fiscal incentives to investment, such as accelerated depreciation or the investment tax credit; as utilities are regulated on a cost of service basis, this reduction in income tax expense would be flowed through to ratepayers in the year in which it occurs. Tax normalization, by contrast, avoids this outcome by stipulating that utility rates “normalize” the benefit of such tax incentives by spreading them out over the useful life of the asset to which they apply. Thus, normalization accounting requires that, in calculating their taxable income and income tax expense for regulatory purposes, utilities depreciate their property, plant and equipment over its useful life and without regard to any provisions of federal tax law allowing the accelerated depreciation of these assets. The result is that during the early years of an asset’s life, a utility’s regulatory accounting, on which cost of service rates are calculated, will show lower depreciation expense and higher taxable income and income tax expense than will appear on the utility’s tax books. The recovery of these costs in rates implies that customers are charged more to defray income tax expense than they would have had flow through accounting been used. In later years, however, the situation reverses; the utility’s tax books, on which accelerated depreciation has been applied, will show the asset to be fully depreciated, while for regulatory accounting purposes depreciation expense will continue to be recorded until the end of the asset’s useful life. As a result, the utility’s regulatory accounts will show higher depreciation expense, and lower taxable income and income tax expense, than will its tax books. During this phase of the asset’s life, customers are charged less to defray the utility’s income tax expense than they would have been had flow through accounting been applied.

To track the difference between the income tax expense recorded on a utility’s regulatory books and the cash taxes actually paid by the utility, normalization accounting, like GAAP, requires the utility to book a deferred tax liability. In the early years of an asset’s life, the utility will record as a liability on its balance sheet the difference between the income tax expense recorded for regulatory purposes and the cash taxes the utility actually pays. In the later years of an asset’s life, when cash taxes fall below book taxes, this liability will be reduced each year by the amount that book taxes exceed cash taxes. Thus, by the end of an asset’s useful life, the deferred tax liability is reduced to zero.Under the current tax code, a dollar added to property, plant and equipment can generate substantial write-offs for tax purposes that are not recognized on utilities’ financial statements, resulting in large deferred tax liabilities. The most important of these tax write-offs is bonus depreciation, which permits 50% of additions to utility plant to be expensed immediately rather than capitalized and depreciated in future years.[2] In recent years, the IRS has also allowed even more rapid expensing of maintenance capital expenditures. IRS regulations adopted in final form in 2013 allow businesses to deduct, rather than capitalize, the cost of repairs to property used in carrying on their business. As a result of the new rules, utilities are now able to expense for tax purposes, rather than capitalize and depreciate, a substantial portion of their maintenance capex.Also significant is accelerated depreciation for tax purposes. The current system of depreciation for tax purposes in the United States (known as Modified Accelerated Cost Recovery System or MACRS), allows wind and solar power plants to be fully depreciated over five years, nuclear power plants and combustion turbine generators to be depreciated over 15 years, and transmission and distribution assets, as well as steam turbine generators and combined cycle gas turbine plants, to be depreciated over 20 years. By contrast, these assets would generally be depreciation over 20 to 40 years for financial accounting purposes, with the average GAAP depreciation rate among U.S. regulated utilities (2.9%) corresponding to a 34-year depreciation schedule.

Exhibit 6 illustrates how the difference between book and tax depreciation drives the accumulation of a deferred tax liability. In the chart, book depreciation is represented by the red columns, tax depreciation by the blue columns and the deferred tax liability by the green columns. All three are presented as a percentage of the value of new plant placed in service. Assuming 50% bonus depreciation and accelerated depreciation per MACRS, ~52% of the value of plant placed in service is written off for tax purposes in year one; GAAP depreciation, by contrast, is less than 3%. Assuming a 35% tax rate, this 49% difference in recognized depreciation expense leads to a year one deferred tax liability of approximately 17% (35% x 49%) of the value of the new plant placed in service. (See the green columns in Exhibit 6 as well as the penultimate line of Exhibit 7.) Because deferred taxes are an offset to property, plant and equipment in the calculation of rate base, for every dollar of capital expenditure the corresponding increase in rate base is only 83 cents. By contrast, if the corporate tax rate were cut to 20%, the first year increase in deferred tax liability would be equivalent to only 10% of the value of plant placed in service (again, see Exhibit 7), allowing each dollar of capex to contribute 90 cents to rate base. The rate base impact of each capex dollar spent would thus rise from 83 to 90 cents, an increase of 8%.

Exhibit 6: The Difference Between GAAP and Tax Depreciation and the Associated Deferred Tax Liability (Assumes MACRS and 50% Bonus Depreciation)

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Source: IRS and SSR analysis

Exhibit 7: Year One Difference Between Tax and GAAP Depreciation and Consequent Increase in Deferred Tax Liability, Assuming MACRS and Various Levels of Bonus Depreciation (Expressed as a % of New Plant in Service)

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Source: IRS and SSR analysis

Implications of the GOP Tax Plan for Rate Base Growth

In our note of October 2, 2017, If This Is the Golden Age of Electric Utilities, What’s Next?[3], we presented our rate base forecasts for the publicly traded U.S. utilities over the periods 2016-2021 and 2021-2025. In this note, we have revised those forecasts to incorporate two key elements of the GOP tax reform framework: first, a reduction in the maximum rate of federal income tax on corporate earnings to 20%, from 35% previously; and, second, a provision allowing corporations to expense rather than capitalize the cost of new investments in depreciable assets. As the GOP tax plan suggests that the expensing of capex may be limited to five years, we have developed two alternative rate base forecasts, one for a scenario in which the expensing of capex is a permanent feature of the tax code and a second for a scenario where it is phased out after five years.

As illustrated in Exhibit 8, we calculate that the combined impact of lower tax rates and the permanent expensing of capex will be to reduce the average rate base CAGR among the regulated utilities by ~80 b.p. to 5.8% p.a. over 2018-2021, and by ~50 b.p. to 4.9% over 2021-2025. Among hybrid utilities, the estimated reduction in rate base growth would be ~90 b.p. to 6.1% over 2018-2021 and ~50 b.p. to 5.1% over 2021-2025.

We estimate that the regulated utilities likely to see the smallest reductions in 2018-2021 rate base growth as a result of the tax plan are ED, ES, HE, OGE, POR and SCG (see Exhibit 8). The largest decreases in rate base growth would likely occur at CMS, DTE, EE, EIX, NWE, and PCG. Among hybrid utilities, EXC and PEG would likely see the smallest reductions in rate base growth, while ETR and NEE would likely suffer the highest.

In Exhibit 9, we present our rate base estimates under the alternative assumption that the GOP tax plan limits the expensing of capex to five years. Over the first five years the tax changes are in effect, this difference has no impact and our rate base forecasts for the industry and individual utilities do not change. Thereafter, however, the rate base growth of the regulated utilities would be expected to accelerate relative to that under the current tax code.

Having expensed in full five years of capital expenditures, utilities would now face significantly reduced depreciation expense for tax purposes. With book depreciation exceeding tax depreciation, utilities’ book income before tax would thus fall below taxable income, and book taxes would fall short of cash taxes due. This would require the utilities to begin to reverse their deferred tax liabilities, boosting rate base growth. As a result, we estimate that the average rate base CAGR among regulated utilities would accelerate by ~60 b.p. to 6.0% p.a. over 2021-2025. Among hybrid utilities, we estimate that rate base growth over 2021-2025 would rise by ~70 b.p. to 6.2%.

The utilities that we would expect to benefit most from the GOP tax plan over 2021-2025 would differ depending upon whether the expensing of capex is assumed to be permanent or to expire after five years (compare the right hand columns of Exhibit 8 and Exhibit 9). If permanent, we would expect rate base growth to fall for all the regulated utilities, relative to growth under the current tax code, but AEP, ED, ES, LNT, WEC and XEL should be least adversely affected. If temporary, we would expect all the regulated utilities to enjoy an acceleration in rate base growth, relative to growth under the current tax code, and for AEE, CMS, LNT, PCG, WEC and XEL to benefit most.

Exhibit 8: Forecast Growth in Electric Rate Base Under Current Tax Code and the

2017 GOP Tax Plan (20% Tax Rate, Permanent Expensing of Capital Expenditures)

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  1. Quintile 1 = smallest decreases, Quintile 5 = largest decreases

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

Exhibit 9: Forecast Growth in Electric Rate Base Under Current Tax Code and the

2017 GOP Tax Plan (20% Tax Rate, Five Year Expensing of Capital Expenditures)

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1. Quintile 1 = smallest decreases, Quintile 5 = largest decreases

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

Tax Reform, the Reversal of Deferred Tax Liabilities and the Implications for Rates

In addition to their impact on rate base growth, the changes proposed in the GOP tax plan would have an effect on the revenue requirement of the regulated utilities and thus on their average rates and customers bills. This effect of the GOP tax plan is a function of how regulated utilities are required to account for changes in their deferred tax liabilities.

When the corporate tax rate changes, companies must recalculate the value of their deferred tax liabilities. The deferred tax liability booked by a corporation when a new asset is brought into service reflects the fact that tax deductions, such as the expensing of capex or the accelerated depreciation of an asset, result in taxable income falling below pre-tax income on the company’s books in the short to medium term, and cash taxes thus running below the provision for income taxes. In the long term, however, the situation reverses; once the asset has been fully depreciated for tax purposes, but continues to be depreciated on the company’s books, book depreciation will exceed tax depreciation, causing book earnings to fall below taxable income and cash taxes to exceed the provision for income taxes (see Exhibit 6). It is this excess of future cash taxes over the provision for income taxes that is reflected in the deferred tax liability on the company’s books. If tax rates are cut, however, the excess of future cash taxes over book taxes will fall as well, and must be reflected in a reduction in the deferred tax liability.

A nonregulated company generally would recognize the reduction in its deferred tax liability as income, which in turn would increase retained earnings and owners’ equity. A utility subject to cost of service regulation would enjoy no such windfall; rather, its regulators would require it to refund the excess deferred taxes to ratepayers.[4] To document this obligation to return the excess deferred taxes to ratepayers, the utility would record a regulatory liability. Like the deferred tax liability that it replaces, this regulatory liability would be an offset to rate base, thus leaving utilities’ existing rate base unchanged.

By way of example, if a utility brought $1.0 billion of utility plant into service in 2017, when the tax rate is 35% and bonus depreciation is 50%, it would immediately expense half of the $1.0 billion for tax purposes. It would also be allowed to commence depreciating the remaining 50% of the value of the asset at a first year rate under MACRS of 3.75%. Together, these provisions of the tax code allow the utility to reduce its taxes by over $180 million (35% x [$1.0 billion x 50% + $500 million x 3.75%] = $182 million). Given the IRS’ requirement of tax normalization, these tax savings are not recognized in the utility’s regulatory accounting. There the depreciation charge would be calculated on a straight-line basis over the life of the asset. Thus, if the asset had a useful life of 40 years, the annual depreciation charge would 2.5% of the asset’s value, and the consequent reduction in the utility’s taxes, for regulatory accounting purposes, would be 35% of this amount or ~$9 million (35% x $1.0 billion x 2.5% = $8.75 million). The excess of the utility’s provision for income taxes over its cash taxes ($182 million – $9 million = $173 million) would be booked on the utility’s balance sheet as a deferred tax liability to be reversed in the later years of the asset’s life.

For tax purposes, depreciation for most utility plant ends in year 21, at which point 100% of the asset’s value would be written off. On the utility’s regulatory books, by contrast, the asset would only be partially depreciated: if it had a 40-year useful life, for example, and thus a 2.5% annual straight line depreciation charge, only 52.5% of the asset’s value would have been written off. At year 21, therefore, the utility would have accumulated a deferred tax liability equal to some $166 million (tax depreciation of $1.0 billion less book depreciation of $525 million = $475 million, and $475 million x 35% = $166 million). Over the final years of the asset’s life, when no depreciation is being taken for tax purposes, book depreciation will exceed tax depreciation by $475 million, causing the utility’s provision for income taxes on its regulatory books to fall short of its cash taxes over these years by $166 million. It is over this period, therefore, that the liability for deferred taxes of $166 million is reversed, offsetting the shortfall in the provision for income taxes on the utility’s income statement.

But if the tax rate in year 22 falls to 20%, the excess of cash taxes over book taxes over the remaining years of the asset’s life would fall to $95 million (book depreciation exceeds tax depreciation over this period by $475 million, and $475 million x 20% = $95 million). The liability for deferred income taxes would be too large as a result, by some $71 million ($166 million – $95 million = $71 million). Since the $71 million in excess deferred taxes had originally been collected from the utility’s customers to cover the utility’s provision for income taxes in the early years of the asset’s life, regulators would now require that it be returned.

Historically, the return of excess deferred taxes has been carried out over the remaining useful life of the assets that gave rise to the deferred tax liability in the first place. Specifically, from an accounting standpoint, the excess deferred tax liability would be replaced with a regulatory liability of equal amount. This regulatory liability would then be amortized over the remaining useful life of the assets, and the benefit transferred to customers as a reduction in rates.

In negotiation with its regulators, however, a utility might offer to amortize the regulatory liability more quickly, thereby mitigating the rate increases that would otherwise be required due to the growth of rate base or increases in operating and maintenance expense. The scale of the benefit could be huge, as Donald Trump might say: we calculate that if the GOP tax plan were adopted, the excess deferred tax liability of the regulated electric utilities as a group would equal 13% of their aggregate electric rate base, equivalent to 36% of their total bundled electric revenues. If this excess were returned over 10 years (equivalent to 3.6% of total retail electric revenue requirement per annum) rather than over the remaining useful life of the assets (assuming this is 30 years, equivalent to 1.2% of regulated electric revenues per annum), then for the next 10 years the utility’s regulated revenues could be lower by ~2.4% than they would otherwise be.

For regulators, a potentially more valuable use of this regulatory liability would be to offer accelerated amortization to achieve other outcomes, such as offsetting spikes in fuel and power prices, an acceleration of inflation or the rate cost of public policy goals, such as modernizing and upgrading the distribution grid. For example, the regulatory liability could be used as a reserve to keep fuel and purchased power price increases below a set rate or to offset the cost of increased investment by the utility in smart meters, energy storage, energy efficiency or renewables. Rate reductions for large industrial customers in order to attract new jobs or retain existing jobs can also be funded this way without a direct increase for other ratepayers. Alternatively, if there is a difficult negotiation, such as over the approval of a new investment, e.g. POR’s proposed wind plant or ETR’s recent increase in nuclear capex and O&M expenses, accelerated amortization could be used to hold rates flat. While such deals will simply shift the time frame over which ratepayers get their own money back, and will have the effect of increasing the utility’s rate base and therefore future rates, regulators and ratepayer advocates have made such deals in the past in order to help reduce current ratepayer bills.

We note that the accelerated reversal of excess deferred taxes would both materially speed the rate of growth in utility rate base, and require the utilities to raise significantly more external capital. To use the example above, we calculate that under the GOP tax plan the excess deferred tax liability of the regulated electric utilities as a group is equal 12.8% of their aggregate electric rate base. If this excess were returned over 10 years (equivalent to ~1.28% of electric rate base per annum) rather that over the remaining useful life of the assets (assuming this is 30 years, equivalent to 0.43% of electric rate base per annum), then over the next 10 years the growth in aggregate electric rate base would accelerate by ~0.85% p.a. (This is a simplified example; in practice, due to the timing of deferred tax reversals, the acceleration in rate base growth would actually be lower at first and higher in later years.)

The return of excess deferred taxes to rate payers through lower customer rates would result in lower cash collections by the utility, triggering an increase in the utility’s financing requirement. Thus, the increase in rate base growth would come at the cost of a commensurate increase in the utility’s capital deployed, equivalent in the above example to ~0.9% of electric rate base each year.

Exhibit 10 presents our estimate of the excess deferred tax liability that would arise at each of the publicly traded electric utilities under the GOP tax plan. For the regulated electric utilities as a group, we calculate that excess deferred taxes would be equal to 14% of aggregate electric rate base, equivalent to 39% of regulated utility revenues. The level varies materially, however, across the regulated utilities. We calculate that AEE, ALE, LNT, PNM, PNW, and PPL will have the largest excess deferred taxes, ranging from 43% to 62% of revenues. Conversely, we calculate that AVA, CMS, HE, IDA, NWE and POR, will have the lowest excess deferred taxes, ranging from 13% to 28% of revenues. The immediate beneficiaries will be those utilities engaged in rate cases or other major regulatory proceedings when the tax reform comes into effect, as they will have a new tool to use in the negotiations.

Exhibit 10: Reduction in Utilities’ Deferred Tax Liabilities Due to 2017 GOP Tax Plan (1)

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1. Assumes 20% maximum corporate tax rate

Source: FERC Form 1, SNL, SSR analysis

The Medium Term Outlook for Utility Rates and Customer Bills Under the GOP Tax Plan

Even if excess deferred taxes were to be returned to rate payers over the remaining useful lives of the utilities’ assets, rather than reversed on an accelerated schedule, utility customers would still benefit from a slower pace of increase in utility rates under the GOP tax plan than they would under the current tax regime. As explained above, we calculate that if the GOP tax plan were adopted, cutting the corporate tax rate to 20% but requiring the expensing of capital expenditures, growth in aggregate rate base over 2018-2021 would decelerate by ~80 b.p. to 5.8% p.a. This slower growth in rate base, combined with a lower corporate tax rate and therefore a lower provision for income taxes, would more than offset the elimination of deductibility of interest on new debt and would be reflected in smaller annual increases in average electricity rates, and in residential customer bills, than would be the case under the current tax regime.

We estimate that under the GOP tax plan, the annual rate of increase for regulated electric utilities in average electricity rates will decelerate by ~40 b.p. to 2.5% p.a. over 2016-2021. Among hybrid utilities, the average increase in average system rates is expected to slow by ~40 b.p. to 1.9% p.a. over 2016-2021. Similarly, we estimate that under the GOP tax plan the annual rate of increase in average residential bills would decelerate by ~40 b.p. to 1.4% p.a. across all utilities. These forecast increases in average system rates of 2.2% p.a. overall are broadly in line with expected inflation, while the estimated growth in average residential bills, at 1.4% p.a., lags expectations of inflation and nominal GDP growth.

Exhibit 11 presents our estimate of the rate of increase in average system rates required by the publicly traded electric utilities through 2021 under the GOP tax plan. As can be seen there, the required level of rate increases varies materially, however, across the industry. We calculate that AEP, ALE, AVA, DTE, LNT, and PNM will require the largest annual increases in average electricity rates through 2021, ranging from 3.1% to 4.5% p.a. under the GOP tax plan. Conversely, we calculate that ED, EE, ES, NWE, OGE, and POR will require the smallest annual increases in rates through 2020, ranging from 1.3% to 1.7% p.a.

Exhibit 12 presents our estimate of the annual increases in average residential bills that would be required through 2021 under the GOP tax plan. We calculate that AEP, ALE, AVA, CMS, DTE, and LNT, will require the largest annual increases in average residential bill s through 2021, ranging from 2.3% to 3.8% p.a. under the GOP tax plan. Conversely, we calculate that ED, GXP, IDA, OGE, POR, and SCG will require the smallest annual increases in rates through 2020, ranging from 0.1% to 0.7% p.a.

Exhibit 11: Impact of 2017 GOP Tax Plan on Average System Rates, 2016-2021

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Source: FERC Form 1, SNL, SSR analysis

Exhibit 12: Impact of 2017 GOP Tax Plan on Average Residential Bills, 2016-2021

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Source: FERC Form 1, SNL, SSR analysis

Regulated Utilities and the Possible Loss of the Tax Deduction for Interest

The tax reform framework released jointly by Republican Congressional leadership and the Trump Administration on September 27 states that “the deduction for net interest expense incurred by C corporations will be partially limited.” Any reduction in the deductibility of interest expense would be recoverable by regulated utilities from ratepayers, and thus would have no long term impact on earnings. For heavily leveraged U.S. utilities, a tax system that disallows the deductibility of interest expense could materially increase utility rates. In combination with a cut in the corporate tax rate to 20%, however, even the complete elimination of the interest deduction would result in a reduction in utilities’ revenue requirement.

This can be demonstrated with a numerical example. On average, U.S. utility regulators permit utilities to fund ~50% of their investment in rate base with equity; the remainder is usually funded with debt. The average rate of interest on the outstanding debt of U.S. electric utilities is approximately 4.5%. Thus, a utility with a rate base of $1 billion would fund $500 million of it with debt, on which it would incur $22.5 million of annual interest expense. At today’s corporate tax rate of 35%, the deductibility of this interest expense reduces the utility’s income taxes by $8 million annually. With interest expense no longer deductible, the utility’s revenues would have to be increased by $8 million to offset the increase in taxes. As we explain below, however, this is materially less than the tax savings that would result from a reduction in the maximum corporate tax rate from 35% to 20%.

The average allowed ROE set by state regulators in electric utility rate cases over the last four quarters has been 9.7%.  In the example above, a 9.7% allowed return on $500 million of equity would permit the utility after-tax earnings of $49 million annually. Grossed up for income taxes at a 35% rate, the equivalent level of income before tax would be $75 million. If the maximum tax rate were reduced to 20%, however, the pre-tax equivalent of $49 million would be only $61 million, a reduction of $14 million. The net impact of the $8 million increase in the after-tax cost of debt, assuming no deductibility of interest, would be more than offset by the $14 million in tax savings from lower tax rates, allowing regulators to reduce the utility’s revenues by a net $6 million.

The Impact of Tax Reform on Utility Cash Flow

The increases in utilities’ deferred tax liabilities that we expect as a result of the GOP tax plan will not only slow pace of growth in rate base; they will also have a material positive impact on utilities’ after-tax cash flow and thus on their capital needs.

In particular, it is clear that the GOP tax plan will be materially positive for utilities’ cash flow over 2016-2021, primarily reflecting the ability to expense capital expenditures in full for tax purposes in the year they are incurred. Under the current tax code, with 50% bonus depreciation and a 35% corporate tax rate, utilities can deduct half of their annual capex and reduce their taxes by 35% of this amount; the net tax reduction is thus equivalent to ~17.5% of a utility’s capital expenditures for the year. If the corporate tax rate is cut to 20%, but utilities are allowed to expense their capital expenditures in full, the net tax reduction is increased to 20% of capex each year.

If the expensing of capex becomes a permanent feature of the tax code, the improvement in utilities’ cash flow will be even more marked in the decade of the 2020s. Under the current tax code, bonus depreciation is scheduled to expire in 2020. During the first year an asset is placed in service, the difference between MACRS depreciation for tax purposes (3.8%) and the average rate of GAAP depreciation among the regulated utilities (2.9%) is only 0.9%; at a 35% tax rate, the net tax reduction is just 0.3% of the cost of the asset. By contrast, full expensing of capex, combined with a 20% tax rate, would allow utilities a net tax reduction of 20% of capex each year.

By contrast, were the expensing of capex to expire after five years, the regulated utilities would experience a material deterioration in cash flow relative to the status quo. By expensing in full five years of capital expenditures, utilities would significantly reduce depreciation expense for tax purposes in the years that follow, causing cash taxes to rise and cash flow to deteriorate. With book depreciation now exceeding tax depreciation, and book taxes lagging cash taxes, utilities would begin to reverse their deferred tax liabilities. The deterioration in cash flow would thus coincide with an acceleration of rate base growth.

In Exhibit 13, we have estimated how the GOP tax plan would affect the cash flow of the regulated utilities and regulated utility subsidiaries of the hybrid utilities. We have estimated the change in cash flow on a cumulative basis over 2018-2021 and again over 2021-2025. Specifically, we have modeled the impact on utilities’ deferred taxes of a reduction in the maximum federal corporate tax rate to 20% and the ability to expense capital expenditures in full in the year in which they are incurred. With respect to the latter, we have modeled two scenarios, one where the expensing of capex is permanent and one where it expires after five years. Finally, we have ranked the utilities into quintiles based upon the ratio of (i) cumulative change in cash flow to (ii) current market capitalization.

Across the utilities as a group, we estimate that cumulative cash flow over 2018-2021 would improve as a result of the GOP tax plan by the equivalent of 1.3% of their aggregate market capitalization. As Exhibit 13 illustrates, the primarily regulated utilities whose cash flow would be most improved over the period 2018-2021 would be CMS, DTE, EE, GXP, NWE and WR, with increases in cumulative cash flow ranging from 2.0% to 2.5% of current market capitalization. The utilities whose cash flow would benefit least, we estimate, would be ED, ES, LNT, OGE, PPL, and WEC, with cumulative cash flow gains ranging from a negative 0.2% to a positive 1.1%. The hybrid utilities that would benefit most would be ETR and FE, while EXC and PEG would benefit least.

Were the expensing of capex to be permanent, the cash flow benefit to the regulated utilities of the GOP tax plan would increase materially beginning in 2020, when under the current tax code bonus depreciation is scheduled to expire. We estimate the cumulative improvement in cash flow over the period 2021-2025 would be equivalent to 3.0% of the regulated utilities’ current aggregate market capitalization. Most positively affected, in this scenario, would be EE, EIX, GXP, PNM, POR and SCG, with cumulative cash flow improvements over 2021-2025 ranging, by our estimate, from 4.0% to 4.7% of current market capitalization.

Conversely, were the expensing of capex to expire after five years, the regulated utilities would experience a material deterioration in cash flow relative to the status quo, with a cumulative deterioration in cash flow over the period 2021-2025 equivalent to 2.4% of the regulated utilities’ current aggregate market capitalization. Most adversely affected in this scenario, we estimate, would be AEE, AEP, EIX, LNT, WEC, and XEL, with cumulative cash flow over 2021-2025 deteriorating by 2.9% to 4.9% of current market capitalization.

Exhibit 13: Change in Cumulative Cash Flow Under Various Tax Scenarios


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

©2017, SSR LLC, 225 High Ridge Road, Stamford, CT 06905. All rights reserved. The information contained in this report has been obtained from sources believed to be reliable, and its accuracy and completeness is not guaranteed. No representation or warranty, express or implied, is made as to the fairness, accuracy, completeness or correctness of the information and opinions contained herein.  The views and other information provided are subject to change without notice.  This report is issued without regard to the specific investment objectives, financial situation or particular needs of any specific recipient and is not construed as a solicitation or an offer to buy or sell any securities or related financial instruments. Past performance is not necessarily a guide to future results.

  1. Rate-regulated utilities are allowed to recover their prudently incurred cost of service in rates, including all costs to procure fuel and purchased power, operation and maintenance expense, depreciation expense, income and other taxes, and a fair return on rate base. Rate base represents the capital invested by a rate-regulated utility monopoly in the supply of a public service (e.g., electricity or gas) and in the U.S. is roughly equivalent to the net depreciated historical value of the utility’s plant, property and equipment. Rate base may be funded by common and preferred equity, long term debt and net deferred tax liabilities. On the debt portion of rate base, utilities are generally allowed to earn a return equivalent to their embedded cost of long term debt. A similar approach is to taken the recovery of the cost of preferred equity. Because a utility’s deferred tax liability largely represents income taxes expensed but not yet paid, and thus does not represent an outlay of capital, regulated utilities are not allowed to earn a return on deferred taxes. As a result, rate base is generally calculated as the net depreciated historical cost of a utility’s property, plant and equipment net of the utility’s deferred tax liability. Finally, on the portion of rate base funded with equity (a proportion set by regulators at a level deemed adequate to sustain an investment grade rating on the utility’s long term debt, and referred to as the “equity ratio”) utilities are allowed to earn a fair return (the utility’s “allowed ROE”) as determined by regulators in periodic rate cases. Given this regulatory framework, it is common for investors to estimate future utility earnings as the product of rate base, the utility’s equity ratio and its allowed ROE.
  2. The rate of bonus depreciation will remain at 50% in 2017 before falling to 40% in 2018 and 30% in 2019. Under current tax law, bonus depreciation will cease altogether in 2020.
  3. The note is available here: 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?
  4. Under normalization accounting, utilities do not pass through to ratepayers the tax benefits of accelerated depreciation during the early years of an asset’s life; rather, customer rates are calculated to recover the higher income tax expense recorded on the utility’s regulatory books, on which assets are depreciated over their useful life. In later years, when an asset is fully depreciated for tax purposes but continues to throw off depreciation expense for book purposes, the utility’s cash taxes will exceed the income tax expense calculated on its regulatory books. In these years, customer rates will fall below the level necessary to defray the utility’s cash taxes; in effect, the utility must return through these lower customer rates the cash it collected from its customers in excess of its cash tax liability during the early years of the assets life. If this future benefit to customers is reduced due to a reduction in the tax rate, a regulated utility cannot pocket the difference but must return any over-collection.
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