Which Utilities May Lose from the Rollback of the Clean Power Plan?

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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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March 16 , 2017

Which Utilities May Lose from the Rollback of the Clean Power Plan?

The Obama administration’s Clean Power Plan to reduce utility emissions of CO2 was welcomed with concealed satisfaction by regulated utilities, for whom the prospect of a capital intensive transition from coal to gas fired and renewable generation represented a welcome addition to investment plans in an era of stagnant power demand. With the Trump administration prepared to withdraw the regulation, which utilities will be most adversely affected?

  • Fossil fueled, steam turbine generating plants – power plants burning coal or fuel oil –account for over 80% of U.S. power plant emissions of CO2. The Obama administration’s Clean Power Plan imposed an obligation upon U.S. generators to transition away from these high emitting power plants to less carbon intensive sources of electricity, including combined cycle gas turbine generators, wind farms and solar photovoltaic arrays. In an era of stagnant power demand, this transition – to be phased in from 2020 through 2030 – represented a welcome long-term avenue for rate base growth for many utilities.
  • Among regulated electric utilities as a group, the capital invested in coal and oil fired power plants accounts for 57% of generation rate base. At utilities with large coal fired fleets, these plants account for between 60% and 80% of generation rate base, and for 20% to 40% of total electric rate base.
  • As illustrated in Exhibit 6, for PPL, AEP and WEC, coal and oil fired power plants account for 70% to 80% of generation rate base, and at CMS, GXP, WR and DTE, for between 60% and 70%.
  • For some regulated utilities, investment in new generation assets is the primary driver of rate base growth through the end of the decade. However, given the stagnation of power demand (see Exhibit 2), generation capex will likely slow post-2020, absent a regulatory requirement to replace or upgrade existing generation. The Clean Power Plan creates such a requirement.
  • At SCG, generation capex accounts for 96% of expected rate base growth through 2020; at NWE, POR and SO, for over 70%; at HE for over 60%; and at LNT and OGE, for over 50% (Exhibit 7).
  • Susceptible to such a slowing in rate base growth, if the Clean Power Plan is withdrawn, are those regulated utilities that (i) rely most heavily upon generation capex for rate base growth through 2020 and (ii) have the highest proportion of coal and oil fired power plants in generation rate base. Principal among these, we calculate, are SCG, SO, HE, GXP, LNT and DTE. (See the quintile rankings in Exhibit 8). To a lesser extent, OGE, CMS, DUK and WR may also be at risk.
  • Least affected by changes in federal regulations with respect to CO2 emissions are those utilities whose regulated rate base comprises primarily transmission and distribution assets. These utilities, where generation capex makes no contribution to rate base growth, include AGR, ED, EIX, ES, EXC, FE, PCG and PEG.
  • Utilities with clean competitive generation fleets could see the future profitability of these assets materially adversely affected by the withdrawal of the Clean Power Plan. In a carbon constrained power market, the nuclear and gas fired generating fleets of EXC and PEG would have expected to enjoy higher generation margins, while the renewable generation fleets of NEE and AGR would likely have enjoyed more rapid growth.
  • Finally, among IPPs, NRG should benefit from the withdrawal of the Clean Power Plan; they have a large coal fired fleet and would thus avoid capex needs and pressure on margins. However, CPN and DYN, similar to the utilities with clean competitive generation fleets, will lose out on the potential for higher margins from the Clean Power Plan.

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

Source: SSR analysis

Details

As an industry, U.S. regulated electric utilities have faced a stiffening headwind to growth in generation rate base as growth in electricity sales slowed markedly in the early years of this century and then stagnated following the Great Recession of 2008-2009. As illustrated in Exhibit 2 below, from 1990 through 2000, U.S electricity sales grew at a compound annual rate of 2.3%; from 2000 through 2007, this slowed to 1.4% p.a.; and from 2007 through 2016, growth in volume sales has turned negative, contracting at an average annual rate of 0.2%

Exhibit 2: U.S. Electricity Sales, 1990-2016 (millions of MWh)

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Source: Energy Information Administration, SSR analysis

Despite this constraint, U.S. regulated utilities have achieved remarkably rapid growth in regulated rate base, which has expanded at a compound rate of 6.5% p.a. since the turn of the century (see Exhibits 3 and 4).

Exhibit 3: Aggregate Electric Rate Base of U.S. Investor Owned Utilities by Asset Category ($ Billions) (1)

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  1. Includes construction work in progress (CWIP)

Source: FERC Form 1, SNL, SSR Analysis

Exhibit 4: CAGR in Electric Rate Base by Asset Class Over Various Periods

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Source: FERC Form 1, SNL, SSR analysis

The rapid growth in rate base since 2000 has been attributable in part to the expansion and hardening of the nation’s high voltage power transmission network: growth in transmission rate base averaged 8.4% p.a. from 2000 through 2015. Despite slowing demand growth, generation rate base has rapid growth as well, expanding at 7.1% p.a. from 2000 through 2015.

In the first years of the century, independent power generators capitalized on increasingly efficient combined cycle gas turbine technology and a prolonged period of low natural gas prices to undertake a massive expansion of the nation’s gas fired generation fleet, ameliorating tightening reserve margins precipitated by a decade of regulatory uncertainty and consequent under-investment by utilities. In subsequent years, capacity additions slowed markedly but generation investment benefitted from increasingly stringent regulation of air emissions, as EPA rules such as the Clean Air Interstate Rule (2005), Cross-State Air Pollution Rule (2011) and Mercury and Air Toxics Standards (2011) gradually forced most coal fired power plants to install costly emissions controls for SO2, NOx, mercury and particulate matter. Many older, smaller coal fired power plants found it uneconomic to undertake these investments and rather ceased operation; the loss of this capacity, in turn, caused utilities in recent years to bring on line replacement generation capacity, mostly gas fired but also including coal gasification and nuclear generating plants.

Exhibit 5: Breakdown of Electric Rate Base of Investor Owned Utilities by Asset Class (%)

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Source: FERC Form 1, SNL, SSR analysis

For many utilities, the Obama administration’s Clean Power Plan represented a further opportunity, primarily in the decade after 2020, to continue large scale investment in generation even in a stagnant market for power. Finalized in August 2015, the Clean Power Plan sought to cut electricity carbon emissions 32 percent below 2005 levels by 2030. States would be required to meet declining annual CO2 emissions targets, forcing a rapid transition from conventional coal fired power plants (which emit, on average, a metric ton of CO2 per MWh) to combined cycle gas turbine generators (emitting only 0.4 metric tons of CO2 per MWh) and carbon-free renewable generation. Achieving the CO2 emissions targets contemplated by the Plan would have required the United States to reduce coal fired generation by approximately a quarter while increase the output of its gas fired fleet by a third.

The Trump administration, however, plans to withdraw the Clean Power Plan and is expected to replace the rule with a regulation of far more limited scope, likely requiring measures to improve the energy efficiency of existing coal fired power plants while avoiding the wholesale transition to lower emitting sources of power. To assess which utilities’ rate base growth is most at risk from this policy shift, we have examined utilities’ regulatory filings with FERC (FERC Form 1 financial statements) to determine which continue to rely most heavily on high emitting coal and oil fired power plants.[1] We have also made reference to utilities’ publicly disclosed capital expenditure plans to assess which companies will see the most rapid growth in generation rate base through the end of the decade.

Among regulated electric utilities as a group, the capital invested in coal and oil fired power plants accounts for 57% of generation rate base. At utilities with large coal fired fleets, these plants account for between 60% and 80% of generation rate base, and for 20% to 40% of total electric rate base. If we exclude FE, which is predominantly a transmission and distribution utility, most heavily exposed are PPL, AEP and WEC, whose coal and oil fired power plants account for 70% to 80% of generation rate base, and CMS, GXP, WR and DTE, where coal and oil fired plants account for between 60% and 70% of generation rate base (see Exhibit 6).

Exhibit 6: Steam Electric Power Plant Rate Base as % of Generation Rate Base

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Source: FERC Form 1, SNL, SSR analysis

For some regulated utilities, investment in new generation assets is the primary driver of rate base growth through the end of the decade. However, given the stagnation of power demand (see Exhibit 2), generation capex will likely slow post-2020, absent a regulatory requirement to replace or upgrade existing generation. The Clean Power Plan created such a requirement.

As illustrated in Exhibit 7, most heavily reliant on generation capex for rate base growth are SCG, whose generation capex accounts for 96% of expected rate base growth through 2020, due to its construction of new nuclear generation units; NWE, POR and SO, where generation capex accounts for over 70% of rate base growth; HE, at over 60%; and LNT and OGE, at over 50%.

Exhibit 7: Share of Generation Investment in Total Electric Rate Base Growth (%)

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Source: FERC Form 1, SNL, SSR analysis

Susceptible to such a slowing in rate base growth, if the Clean Power Plan is withdrawn, are those regulated utilities that (i) rely most heavily upon generation capex for rate base growth through 2020 and (ii) have the highest proportion of coal and oil fired power plants in generation rate base. Among the companies in the intersection of these two sets, we calculate that those most at risk are SCG, SO, HE, GXP, LNT and DTE. (See the quintile rankings in Exhibit 8). To a lesser extent, OGE, CMS, DUK and WR may also face a slowing of rate base growth.

Least affected by changes in federal regulations with respect to CO2 emissions are those utilities whose regulated rate base comprises primarily transmission and distribution assets. These utilities, where generation capex makes no contribution to growth in regulated rate base, are AGR, ED, EIX, ES, EXC, FE, PCG and PEG (Exhibit 8).

Utilities with clean competitive generation fleets could see the future profitability of these assets materially adversely affected by the withdrawal of the Clean Power Plan. In a carbon constrained power market, the nuclear and gas fired generating fleets of EXC and PEG would have expected to enjoy higher generation margins, while the renewable generation fleets of NEE and AGR would likely have enjoyed more rapid growth.

Finally, among independent power producers, CPN, with its gas and renewable generation fleet will be most adversely affected by the absence of the Clean Power Plan. DYN and NRG have made efforts to clean up their generation fleets, repowering to gas, retiring coal and adding renewables. For DYN, the loss of the Clean Power Plan is likely slightly negative, as the benefits it would have generated for its gas fleet probably exceed the pressure it would place on margins on its smaller coal

fleet. For NRG, however, the absence of the Clean Power Plan should be a positive, as it has a much larger reliance on coal fired generation than the other IPPs.

Exhibit 8: Steam Electric Plant as a % of Total Electric Rate Base and Investment in Generation as % of Total Electric Rate Base Growth, 2015-2020

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Source: FERC Form 1, SNL and SSR analysis

Exhibit 9 presents our forecast of the growth in electric rate base at each of the regulated U.S. electric utilities through the end of the decade. Our estimates of future rate base are based upon (i) the year-end 2015 rate base of the various investor owned electric utilities, as reported in their FERC Form 1 financial statements, (ii) the capital expenditure plans of these utilities over 2016-2020, as disclosed by management in SEC filings and investor presentations, (iii) expected depreciation in these years at each utility’s current depreciation rate, and (iv) the net change in deferred taxes (an offset to rate base) resulting from difference in tax and GAAP depreciation rates, the 50% bonus depreciation allowed upon the entry into service of new utility assets, and the reversal of these effects for prior years investments. For a fuller description of our analysis, please see our note of September 13, 2016, Is This the Golden Age of Electric Utilities?

Exhibit 9: Historical and Forecast Growth in Electric Rate Base of U.S. Utilities

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Source: FERC Form 1, 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. We estimated the coal and oil generation rate base based on the investment in “Steam Production Plant” in the Form 1. Although some utilities include steam-related plant at combined cycle gas turbines in this category, we estimate that >90% of the investment in this category represents coal and oil fired generation based on the aggregate gross investment in coal and oil fired power plants listed by each utility in the “STEAM-ELECTRIC GENERATING PLANT STATISTICS” section of the Form 1.
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