The Power of Deferred Taxes: How Tax Reform Can Speed Rate Base Growth and Cut Customer Rates

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_____________________________________________________________________________________

Eric Selmon

Office: +1-646-843-7200

Email: eselmon@ssrllc.com

Hugh Wynne

Office: +1-917-999-8556

Email: hwynne@ssrllc.com

SEE LAST PAGE OF THIS REPORT FOR IMPORTANT DISCLOSURES

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December 15, 2016

The Power of Deferred Taxes:

How Tax Reform Can Speed Rate Base Growth and Cut Customer Rates

If tax rates are cut, utilities will be required to reverse a significant portion of their deferred tax liabilities, and to return this excess to customers. We calculate that utilities’ excess deferred taxes would equal 13% of aggregate electric rate base under the House GOP tax plan and 17% under the Trump tax plan, or the equivalent of 26% of total bundled utility revenues under the House plan and 34% under the Trump plan. Depending on how quickly these excess deferred taxes are returned to customers, rate payers could thus enjoy very material rate relief — and utilities a significant acceleration in rate base growth. Utilities, however, would require additional capital to fund this growth, increasing their reliance on external financing.

Portfolio Manager’s Summary

  • The keystone of both the Trump and House GOP plans is a radical reduction in the corporate tax rate, from 35% currently to 20% under the House plan and to 15% under the Trump plan. At these lower tax rates, the value of regulated utilities’ deferred tax liabilities would be dramatically reduced; we calculate that utilities’ excess deferred taxes would represent:
    • 13% of aggregate electric rate base under the House GOP plan and 17% under the Trump tax plan, equivalent to
    • 26% of utilities’ bundled revenues under the House GOP plan and 34% under the Trump plan.
  • Utility regulators will require these excess deferred taxes to be returned to rate payers. 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. In negotiation with its regulators, however, a utility might offer to amortize the regulatory liability more quickly.
  • The accelerated reversal of excess deferred taxes could mitigate the rate increases that a utility would otherwise require, due to growth in rate base or increases in operating expenses, while offering regulators a tool to achieve other outcomes, such as offsetting spikes in fuel and power prices, an acceleration of inflation or the cost of public policy goals, such as modernizing and upgrading the distribution grid.
  • At the same time, the accelerated reversal of excess deferred taxes would materially speed the rate of growth in utility rate base. Utilities, however, would require additional capital to fund this growth.
  • We calculate that ALE, ETR, LNT, OGE, PNM, PNW and WR will have the largest excess deferred taxes, ranging from 37% to 58% of revenues under the House GOP plan and from 49% to 76% under the Trump plan. Conversely, we calculate that AGR, CMS, ED, ES, HE, NEW and POR, will have the lowest excess deferred taxes, ranging from 7% to 18% of revenues under the House GOP plan to 9% to 23% under the Trump plan. (See Exhibit 3).
  • The immediate beneficiaries will be those utilities engaged in rate cases or other major regulatory proceedings when the tax reform takes effect, as they will have a new tool to use in the negotiations.
  • 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 Trump and House GOP tax plans than they would under the current tax regime. We estimate that average electricity rates will rise by 2.5% p.a. through 2020 under the current tax code but by only 2.1% p.a. under both tax plans.
  • As explained in our note of November 29, How Will the Trump and GOP Tax Plans Impact Rate Base Growth? The Opportunity and Risk Facing Utility Investors, we calculate that if the House tax plan were adopted, cutting the corporate tax rate to 20% but requiring the expensing of capital expenditures, growth in aggregate rate base over 2015-2020 would decelerate to 6.3% p.a. from 6.6% under the current tax code.
    • This slower growth in rate base, combined with a lower corporate tax rate and therefore a lower provision for income taxes, 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.
  • If the Trump tax plan were adopted, cutting the corporate tax rate to 15% but not requiring the expensing of capex, we calculate that the growth in aggregate electric rate base would accelerate to an average of 7.5% per annum through 2020, up from 6.6% under the current tax code.
    • While this acceleration in rate base growth would tend to drive rates higher, this effect is offset by the ~60% reduction in the corporate tax rate, from 35% to 15%, under the Trump plan.
  • Exhibit 4 presents our estimate of the annual rate increases required by investor owned electric utilities through 2020 under the current tax regime and the Trump and House GOP tax plans. Exhibit 5 presents our estimates of the annual increases required in average residential bills. For an in-depth analysis of how rate base growth affects the future pace of increase in electricity rates and average bills, please see our note of October 31, Why Rate Base Growth Will Far Outpace GDP, But Rates Will Not.
  • Exhibit 1 presents an updated heat map of our preferences among utility, IPP and clean tech stocks. The arguments supporting our latest views are summarized in Appendix 1.

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


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

Details

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

The U.S. federal tax code requires the use of tax normalization accounting by regulated utilities. This means that regulated utilities, in calculating their taxable income and income tax expense for regulatory purposes, must 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. By contrast, through provisions such as bonus depreciation, MACRS depreciation and the repair deduction[1], the tax code allows the rapid expensing of assets for tax purposes. The result is that during the early years of an asset’s life, a utility’s regulatory accounting will show much lower depreciation expense, and thus much higher taxable income and income tax expense, than will appear on the utility’s tax books. Regulators calculate the appropriate level of a utility’s cost-of-service-based rates based upon its regulatory accounting, implying that the utility’s customers will be charged to cover the provision for income taxes on a utility’s regulatory books even if its cash taxes are materially lower. The difference between the utility’s book provision for income taxes and its actual tax liability is booked on the utility’s balance sheet as a deferred tax liability.

In later years, 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. The utility’s book provisions for income taxes will therefore fall short of its actual cash taxes. The utility then begins to reverse its deferred tax liability, amortizing it to offset the excess of cash taxes over book income tax expense. During this phase of the asset’s life, customers are charged less to cover the utility’s income taxes than the utility actually pays. The difference between tax and book depreciation, and the consequent build-up and reversal of the deferred tax liability associated with a utility asset, is illustrated in Exhibit 2.

Exhibit 2: The Difference Between Book and Tax Depreciation and the Consequent Build-Up and Reversal of the Deferred Tax Liability Associated with a Utility Asset (1)

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1. Assumes 50% bonus depreciation and MACRS

Source: IRS and SSR analysis

When tax rates are changed over the life of a utility’s assets, however, the deferred tax liability to which the depreciation of these assets gave rise must now be recalculated. If, for example, a utility brought $1.0 billion of utility plant into service in 2016, 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 15%, the excess of cash taxes over book taxes over the remaining years of the asset’s life would fall to $71 million (book depreciation exceeds tax depreciation over this period by $475 million, and $475 million x 15% = $71 million). The liability for deferred income taxes would be too large as a result, by some $95 million ($166 million – $71 million = $95 million). Since the $95 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 Trump tax plan were adopted, the excess deferred tax liability of the regulated electric utilities as a group would equal 17% of their aggregate electric rate base, equivalent to 34% of their total bundled electric revenues. If this excess were returned over 10 years (equivalent to 3.4% of total bundled electric revenues per annum) rather that over the remaining useful life of the assets (assuming this is 34 years, equivalent to 1.0% 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 Trump tax plan the excess deferred tax liability of the regulated electric utilities as a group is equal 17% of their aggregate electric rate base. If this excess were returned over 10 years (equivalent to 1.7% of electric rate base per annum) rather that over the remaining useful life of the assets (assuming this is 34 years, equivalent to 0.5% of electric rate base per annum), then over the next 10 years the growth in aggregate electric rate base would accelerate by ~1.2% 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.)

Critically, 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 consequent 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 ~1.2% of electric rate base each year.

Exhibit 3 presents our estimate of the excess deferred tax liability that would arise at each of the investor owned electric utilities under the Trump and House GOP tax plans. For the industry as a whole, we calculate that excess deferred taxes would be equal to 13% of aggregate electric rate base under the House GOP plan and 17% under the Trump tax plan, equivalent to 26% of regulated utility revenues under the House GOP plan and 34% under the Trump tax plan. The level varies materially, however, across the industry. Thus we calculate that ALE, ETR, LNT, OGE, PNM, PNW and WR will have the largest excess deferred taxes, ranging from 37% to 58% of revenues under the House GOP plan and from 49% to 76% under the Trump plan. Conversely, we calculate that AGR, CMS, ED, ES, HE, NEW and POR, will have the lowest excess deferred taxes, ranging from 7% to 18% of revenues under the House GOP plan to 9% to 23% under the Trump plan. 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 3: Lower tax rates will materially reduce utilities’ deferred tax liabilities, and the reversal of these liabilities will have a material impact on utilities’ revenues and rate base

Source: FERC Form 1, SNL, SSR analysis

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 Trump and House GOP tax plans than they would under the current tax regime. As explained in our note of November 29, How Will the Trump and GOP Tax Plans Impact Rate Base Growth? The Opportunity and Risk Facing Utility Investors, we calculate that if the House tax plan were adopted, cutting the corporate tax rate to 20% but requiring the expensing of capital expenditures, growth in aggregate rate base over 2015-2020 would decelerate to 6.3% p.a. from 6.6% under the current tax code. 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 average electricity rates will rise by 2.5% p.a. through 2020 under the current tax code but by only 2.1% p.a. under the House tax plan. Similarly, we estimate that average residential bills will rise by 1.9% p.a. under the current tax regime and by only 1.5% p.a. under the House tax plan.

If the Trump tax plan were adopted, cutting the corporate tax rate to 15% but not requiring the expensing of capex, we calculate that the growth in aggregate electric rate base would accelerate to an average of 7.5% per annum through 2020, up from 6.6% under the current tax code. While this acceleration in rate base growth would tend to drive rates higher, this effect is offset by the ~60% reduction in the corporate tax rate, from 35% to 15%. Under the current tax regime, a utility whose allowed ROE is 10% must earn a pre-tax return of 15.4% its equity if it is to achieve its ROE is to achieve its allowed level. At a 15% tax rate, the pre-tax return on equity consistent with a 10% allowed ROE is only 11.8%. Given an allowed equity ratio of 50% of rate base, the cut in the tax rate is alone sufficient to reduce the utility’s revenue requirement by the equivalent of 1.8% of rate base (50% x [15.4% – 11.8%]), or the equivalent of 0.9% of regulated revenues. By contrast, the increase in annual rate base growth of 0.9%, would be reflected in an increase of just 0.4% in regulated revenues (on average, only 39% of regulated utility revenue is required for the return of and on invested capital, or rate base, and 0.9% x 39% = 0.4%). As a result, while we estimate that average electricity rates will rise by 2.5% p.a. through 2020 under the current tax regime, an increase of 2.1% p.a. would be required under the Trump tax plan.

Exhibit 4 presents our estimate of the annual rate increases required by investor owned electric utilities through 2020 under the current tax regime and the Trump and House GOP tax plans. For the industry as a whole, we calculate that average electricity rates will rise by 2.5% p.a. through 2020 under the current tax regime and by ~2.1% p.a. under the Trump and House tax plans. The required level of rate increases varies materially, however, across the industry. Thus we calculate that AVA, DTE, LNT, PNM, SCG, WR and XEL will require the largest annual increases in average electricity rates through 2020, ranging from 4.4% to 5.0% p.a. under the current tax regime to 2.7% to 3.4% p.a. under the Trump and House GOP tax plans. Conversely, we calculate that ED, EE, ES, EXC, FE, NWE and OGE, will require the smallest annual increases in rates through 2020, ranging from 1.4% to 1.9% p.a. under the current tax regime and from 1.2% to 1.8% p.a. under the Trump and House GOP tax plans.

Exhibit 5 presents our estimate of the annual increases in average residential bills through 2020 under the current tax regime and the Trump and House GOP tax plans. For the industry as a whole, we calculate that average residential bills will rise by 1.9% p.a. through 2020 under the current tax regime and by 1.5% p.a. under the Trump and House tax plans.

For an in-depth analysis of how rate base growth affects the future pace of increase in electricity rates and average bills, please see our note of October 31, Why Rate Base Growth Will Far Outpace GDP, But Rates Will Not.

Exhibit 4: Rate base growth will drive only a small annual increase in average electricity rates, particularly under the Trump and House GOP tax plans

Source: FERC Form 1, SNL, SSR analysis

Exhibit 5: Rate base growth will drive only a small annual increase in average residential electricity bills, particularly under the Trump and House GOP tax plans

Source: FERC Form 1, SNL, SSR analysis

Appendix

Exhibit 1 presents an updated heat map of our preferences among utility, IPP and clean tech stocks. The arguments supporting our latest views are summarized below.

Favorite Stocks

EIX

  • Rate base growth above 7% p.a. through 2020, with strong regulatory support for grid modernization
  • Low dividend payout (~50%) allows growth to be funded internally, avoiding equity issuance
  • Triennial forward looking rate cases minimize regulatory lag, permitting earned ROE to reach allowed level
  • Triennial cost of capital proceedings and indexation of allowed ROE to utility bond yields
  • As a T&D utility, Edison faces lower construction, financial and regulatory risk than vertically integrated peers

EXC

  • Very cheap on 2018 guidance, which should be easily achieved with ZECs in Illinois
  • Rapid rate base growth, funded with internally generated cash, and rising earned ROE at Pepco
  • PE tailwind from rising contribution of regulated earnings
  • Upside from tax reform both at generation and at Pepco utilities because they are under earning
  • ROE indexed to 30 year US Treasury yield at Illinois utility, and some inflation protection due to forward looking rate cases in Illinois and for FERC-regulated transmission assets

NEE

  • Historically the fastest growing and best managed of US utilities, NEE is now available at an industry average valuation, oversold on concerns about renewables under Trump
  • Above average earnings growth is likely to continue, powered, in part, by the Oncor acquisition. Oncor offers the opportunity for increased regulated investment even above even the recently increased capex guidance for 2017-2021
  • $0.50 eps upside from impact of lower tax rates on NEE’s competitive business
  • Tax cuts will lower cash flows from recent and new renewables projects, but will improve cash flows from older projects (>8000 MW pre-2011)

PCG

  • Top quintile rate base growth (>8% CAGR over 2015-2020) not reflected in discounted valuation
  • Critically, given PCG’s high capex, forward looking rate cases match future revenue to rate base
  • Gas and electric rate cases (2016 and 2017, respectively) will allow earned ROE to recover its allowed level
  • ROE relief due to triennial cost of capital proceedings and indexation of allowed ROE to utility bond yields
  • Potential for multiple expansion as operating performance and regulatory relations improve

PEG

  • One of the fastest growing utilities (>9% annual rate base growth, 2015-2020) at a discounted valuation
  • Strong balance sheet, merchant generation cash flow limit need for external equity
  • Merchant generation risk, but also upside from any cut in tax rates
  • Inflation protection as >50% of rate base under riders or FERC transmission with forward looking rates
  • PE tailwind as rapid growth in regulated business reduces share of merchant generation earnings

Concerns

ALE

  • Bottom quintile rate base growth (~2% CAGR, 2015-2020) and limited opportunities for long term improvement — yet ALE trades at a premium valuation
  • Rate case risk with current allowed ROE 60 bps above most recent MN allowed ROE
  • While industrial sales provide leverage to stronger economic growth, mining customers depend heavily on China and are at significant risk in the event of an economic slowdown, trade war or diplomatic confrontation

D

  • Premium valuation contrasts with average growth in electric rate base (~5.5% CAGR, 205-2020)
  • Extremely low quality operating earnings used to meet overly optimistic guidance and mask historically poor eps growth
  • With high holdco debt, D is at risk from the House GOP plan to disallow the deductibility of interest
  • Reduction in corporate tax rate could force cut in maximum allowed rate at FERC regulated pipelines
  • MLPs with a tax allowance under FERC regulated rates would see a reduction in the tax allowance

ETR

  • Expensive relative to other hybrid utilities in spite of slow earnings growth and downside risks
  • Issues with competitive nuclear fleet could cost more and take longer to resolve than forecast
  • Continued problems at regulated nuclear fleet could result in disallowance of incremental nuclear capex
  • Tax reform would be negative as it would reduce the value of NOLs and limit opportunities to make up for earnings shortfalls with one-time tax benefits
  • Large holdco debts means ETR is also at risk from the potential loss of deductibility of interest

©2016, SSR LLC, 225 High Ridge Road, Stamford, CT 06905. All rights reserved. The information contained in this report has been obtained from sources believed to be reliable, and its accuracy and completeness is not guaranteed. No representation or warranty, express or implied, is made as to the fairness, accuracy, completeness or correctness of the information and opinions contained herein.  The views and other information provided are subject to change without notice.  This report is issued without regard to the specific investment objectives, financial situation or particular needs of any specific recipient and is not construed as a solicitation or an offer to buy or sell any securities or related financial instruments. Past performance is not necessarily a guide to future results.

  1. 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. For a more detailed discussion of various forms of accelerated depreciation and deferred taxes, see our note from September 21, The Impact of Deferred Taxes on Utility Rate Base Growth. 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. 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.
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