|Shares Out. (in M):||315||P/E||25.0||23.4|
|Market Cap (in $M):||27,702||P/FCF||N/A||N/A|
|Net Debt (in $M):||12,392||EBIT||1,649||1,812|
|Borrow Cost:||General Collateral|
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WEC Energy Group, Inc. (“WEC”)
Short WEC at $88, 27% downside to $65 price target; buy XLU Jan 2020 $65 calls for $0.26 (vs. $62.43 reference price) to hedge rate risk
Regulated utility equities have soared to record highs on skyrocketing earnings multiples as bond yields have declined and as utility equities have seen vast inflows from exchange-traded funds targeting low volatility. Falling rates aside, the low-vol march upward has been underpinned by the utility industry’s relative immunity from both volatile U.S. trade policy and a slowing macro picture, but I believe continued enthusiasm for utility stocks is misguided at current levels. While the broad strokes of this thesis could apply to a number of utilities, I believe WEC is most negatively exposed to a number of near- and medium-term fundamental catalysts that should drive negative revisions to earnings estimates and valuation multiples. In summary:
Rate base growth of 6-7% is unsustainable in the face of continuing secular declines in electricity consumption and growing ratepayer opposition to full recovery of stranded costs associated with accelerated coal plant retirements;
Authorized rates of return are coming down as regulators account for falling bond yields and recognize increasing divergences between authorized and actual capital structures;
WEC has generated little unlevered free cash flow in the last decade and worsening credit metrics will likely force the company to reduce dividend growth guidance to avoid rating agency downgrades; and
Reliably poor regulated returns on invested capital should exert downward pressure on valuation multiples, and the resulting unwind could lead to a cascade of selling as low volatility ETFs divest large utility industry weightings.
WEC is a regulated utility serving 1.6 million electric and 2.9 million natural gas customers in Wisconsin, Illinois, Michigan, and Minnesota. The company owns a 60% stake in American Transmission Company (“ATC”), a for-profit electric transmission company regulated by FERC, non-utility energy infrastructure operations through its subsidiaries We Power (generation assets in Wisconsin), Bluewater (underground natural gas storage in Michigan), and majority equity stakes in numerous wind generating facilities. WEC’s retail delivery is roughly equally split between residential, small C&I, and large C&I customers. Regulated revenue splits by business and by jurisdiction are shown below.
Source: WEC November 2019 investor presentation
WEC has one of the more ambitious capital spending programs among its peers, with plans to grow the company’s regulated asset base by 7% per year through 2024 primarily through investments in natural gas, solar, and wind generation projects.
As of December 2018, WEC’s electric generation facilities had rated capacity of 7,328 MW, comprised of 48% coal, 29% natural gas, 20% natural gas/oil peakers, and 3% renewables.
Current situation / consensus perception
WEC shares are up 31% YTD as regulated utilities broadly have rallied on a combination of declining bond yields and perceived ability to grow earnings 5-7% per year in the face of trade uncertainty and a slowing macro picture. WEC has outperformed regulated utility peers given strong forward rate base growth guidance and a heretofore utility-friendly regulatory posture in Wisconsin, home to the majority of WEC’s regulated rate base.
The bull case for WEC rests on three key planks. First, mid- to high-20s earnings multiples can be justified given low UST yields and WEC’s robust growth capex budget. WEC plans to grow its regulated rate base from $19.8 billion as of 2018 to $30.2 billion by 2024 (7% CAGR), with investments concentrated in gas and electric distribution. These are 30+ year investments that will earn 10% returns on equity (absent authorized rate changes), well in excess of WEC’s current cost of equity. Such a long run of returns on capital in excess of WEC’s cost of capital would indeed deserve a premium multiple, as shown below.
Second, WEC’s capex budget is heavily skewed to renewable generation and grid modernization projects as part of the company’s heavily touted plan to reshape its generation fleet. WEC retired its 1,190 MW Pleasant Prairie plant in April 2018, and expects to retire an additional 1,800 MW of coal-generation by 2020 as part of an eventual goal to reduce CO2 emissions by 40% below 2005 levels by 2030, and by 80% below 2005 levels by 2050. The company claims the Pleasant Prairie retirement alone will save ratepayers billions of dollars over the next two decades.
Even better, the carrying value of retired power plants is classified as a regulatory asset on WEC’s balance sheet. As long as FERC finds that capex associated with these plants was prudently incurred, WEC can continue to collect the carrying value of the plants using approved depreciation rates, in addition to an equity return on the remaining carrying value. The company does not disclose carrying value by plant, but by applying Pleasant Prairie’s carrying value per MW to WEC’s remaining coal-fired generation capacity, WEC could earn equity returns on $975 million (beginning 2021) to $1.9 billion (assuming full retirement of WEC’s coal-fired capacity) of carrying value with no benefit to ratepayers.
Finally, depressed coal and natural gas prices can continue to shield ratepayers from above-market authorized returns on equity and unrelenting rate base growth. Since 2011, WEC’s fuel costs per MWh for coal, natural gas combined cycle, and natural gas/oil peaking units have declined by 21%, 43%, and 59%, respectively. These three sources accounted for 97% of WEC’s rated capacity as of December 2018.
Long-run rate base growth of 6-7% will soon prove politically unjustifiable
U.S. electricity generation peaked prior to the financial crisis in 2007 at 4,164 TWh and only just recovered that level in 2018 at 4,177 TWh (I use EIA’s generation data as a proxy for demand). Generation in Wisconsin and Illinois — WEC’s two primary markets — has grown by 0.36% and shrunk by 0.57% per year since 2007, respectively (see generation mix evolution for each state in the appendix). Total MWh-equivalent usage among WEC’s customer base increased by just 1.1% YTD 2019 vs. 2018 even as total heating and cooling degree days increased by 2.0%.
Per capita electricity generation has been flat or declining since 2007 even as economic activity picked up following the financial crisis. Commentators have offered numerous justifications for stagnant electricity demand, but most agree the main contributors have been energy efficiency initiatives (primarily increasing use of LED light bulbs), dematerialization, warmer weather, and greater outsourcing of heavy industry.
And yet, regulated utilities have continued to increase capital spending to maintain rate base growth targets in the mid- to high-single digits. WEC in particular touts its growth track record: three of the first six slides of the company’s latest investor presentation highlight a history of EPS beats and consistent dividend growth. This behavior writ large, in combination with secularly declining electricity demand, has pushed electric power generation capacity utilization to historical lows.
These dynamics have raised concerns (although one wouldn’t know it looking at current utility valuations) of an electric utility “death spiral” created by advances in distributed energy resources and consumer demand for cleaner energy. Nearly half of utilities surveyed in September 2018 said centralized power is “losing its relevance in a world with a preference for cheaper distributed generation,” and worried about the prospect of commercial and industrial customers as potential competitors.
Utilities — particularly those with a large proportion of coal-fired generation capacity, like WEC — are now pivoting to embrace renewable generation in a shift that can be interpreted laudably as well as cynically. Sell-side research is replete with bullish theses in which utilities have vast capital spending runways (accelerating rate base growth) in supportive regulatory regimes that permit full recovery, including equity returns, of undepreciated assets comprised of coal-fired power plants facing early retirement.
There are two major holes in this thesis: increasing regulator pushback on stranded asset recovery and falling construction costs for renewables that will translate into lower rate bases over time. We can look to a recent decision involving WEC for color on the first.
When WEC shut down its Pleasant Prairie power plant in April 2018, it sought to recoup the remaining $645 million in book value plus more than $430 million in profits from ratepayers. WEC argued that early closure would save customers $2.5 billion over the next two decades and reminded regulators that they had approved construction of the plant as well as subsequent expenditures on pollution controls. WEC argued this spending met the “prudent incurrence” standard and that under the regulatory compact, the company deserved to earn a guaranteed return on its investment. (In deregulated states, like Ohio, companies must write off retired plants’ value.)
Consumer advocates fought back, arguing WEC should be allowed to recover its investment in Pleasant Prairie, but should not earn a 10% equity return on an investment that is sitting idle and not “used and useful” to ratepayers from 2020 onward. In August 2019, WEC reached an agreement that will allow the company to refinance just $100 million of its investment in Pleasant Prairie through a securitization backed by charges added to ratepayer bills, in addition to a regulated return on $151 million of remaining book value.
Pleasant Prairie marks one of the first uses of securitization by a utility to recover stranded coal assets, and it likely will not be the last. Colorado, New Mexico, and Montana put forward legislation in 2019 that would favor securitization to deal with stranded assets. Utilities have historically favored accelerated depreciation of redundant coal plant PP&E to quickly resolve stranded asset balances. But accelerated depreciation also accelerates rate increases borne by ratepayers, who are increasingly questioning whether utility investments were prudently incurred.
Falling renewable energy operating and capital costs are set to further suppress prospective rate base growth. Lazard’s latest Levelized Cost of Energy Analysis found that operating costs of utility scale onshore wind ($28/MWh) and solar ($36/MWh) are competitive with conventional generation ($34/MWh for coal and $29/MWh for nuclear) when including government subsidies. Competitive operating costs should help accelerate adoption of renewables, and consistently declining capital costs should worry utility shareholders as they imply lower contributions to the rate base. Capital costs per kW are now $900-$1,500 for utility scale wind and solar vs. $6,900-$12,200 for nuclear and $3,000-$6,250 for coal.
Finally, WEC ratepayers have been insulated from unrelenting rate base growth by consistent declines in fuel costs, which are down 50% since 2008. Fuel and purchased power represented 38% of rates paid by customers in 2018, and any reversal in the last decade’s coal and natural gas price declines would represent yet another hurdle to increases in rate base and/or regulated returns on equity.
Source: WEC SEC filings
Authorized rates of return are coming down as regulators account for falling bond yields and recognize increasing divergences between authorized and actual capital structures
I am not predicting any fireworks in this part of the thesis other than to note that public utility commissions have been approving steadily lower authorized returns on equity as Treasury yields have declined. Thus, there is less fundamental justification for utility industry P/E multiples to rise as rates drop than in other rate-sensitive sectors where companies can increase the spread between ROICs and costs of capital.
Source: Edison Electric Institute
Finally, the traditional regulatory compact holds that in exchange for a protected monopoly, utilities should earn a “reasonable” return on capital invested in the enterprise — there is no regulatory obligation to maintain elevated utility market valuations. With awarded ROEs at spreads to 10-year Treasuries and BBB bond yields well above pre-financial crisis averages, it is not difficult to make the argument that utilities have been earning excess rents at the expense of ratepayers.
Ratepayers in South Carolina were successful in advancing such an argument in May. A Duke Energy subsidiary had requested an ROE of 10.5% and a tripling of a fixed charge rate that has been criticized by consumer advocates as burdening low-energy usage customers. South Carolina regulators approved a 9.5% ROE, proposed to restrict the contribution from customers to executive pay, and disallowed Duke from recovering $333 million in coal ash costs from a North Carolina clean-up.
I am not suggesting that in this case the plural of anecdote is data, but will note that absent a sharp rise in Treasury yields, PUCs appear to have room — in the face of growing ratepayer pressure — to bring down authorized ROEs by one to two percentage points in the coming years.
One final note on allowed returns on equity. The two key parameters in a ratemaking proceeding are return on equity and the equity layer (i.e., the proportion of equity in the capital structure at the utility subsidiary level). While the primary focus of this section has been to discuss the potential for lower ROEs, it is worth spending some time on the equity layer. As part of WEC’s August 2019 rate settlement, the PSCW lowered 2020 authorized ROEs for WEC’s Wisconsin Electric and Wisconsin Gas subsidiaries by 20 bps and 10 bps, respectively, while raising the midpoint equity layer for those subsidiaries by 150 bps and 300 bps, respectively, in essence sneakily raising authorized dollar operating income (PSCW raised the equity layer at WEC subsidiary Wisconsin Public Service by 100 bps while leaving ROE flat).
PUCs have held that the authorized equity layer at a utility subsidiary should generally reflect the actual capital structure. This has resulted in utilities levering up at the holding company level to cover rising dividend payouts and increasingly negative FCF.
This feeds back into the cost of equity calculation at the subsidiary level. As attorney Scott Hempling pointed out in 2014, the true cost of a subsidiary’s equity capital is the overall cost of the parent’s capital. Accordingly, increased debt at the holding company level (barring downgrades) will artificially lower the cost of capital at the subsidiary, imposing extra costs on ratepayers through a process Hempling calls “double leveraging” — i.e. ratepayers will pay more to the ultimate equity holders than their actual cost of equity invested in the utility.
Lack of FCF and deteriorating credit metrics will likely force management to rein in dividend growth expectations to avoid rating agency downgrades
WEC has generated virtually zero free cash flow in the last ten years (while paying zero cash taxes by virtue of continuous capex outspend of D&A) and has financed its growing common equity dividend (as well as $1.2 billion of share buybacks largely to offset dilution from employee stock option exercise!) by leveraging the balance sheet.
Source: WEC SEC filings
WEC peer FirstEnergy provided some color on rating agency guidelines for the utility industry on its Q4 2018 earnings call. WEC and FirstEnergy’s holding company bonds are both currently rated BBB by S&P and trade at comparable yields. Per FirstEnergy CFO Steven Strah, S&P tracks FFO to total debt (minimum threshold of 9%), Moody’s tracks CFO to total debt (minimum threshold of 12%), and Fitch tracks FFO adjusted leverage (maximum threshold of 6.5x, equivalent to ~15% FFO to total debt). Assuming very slight declines in allowed ROEs (35 bps cumulatively through 2022) and equity layer (50 bps cumulatively through 2022, still more favorable than 2019 levels), and assuming 6% dividend per share growth per current company guidance, net debt / EBITDA will be 5.6x and FFO / net debt will be sub-15% by December 2020.
Source: WEC SEC filings, author projections
I believe WEC will seek to preempt any holding company downgrades by lowering dividend growth guidance (and perhaps rate base growth guidance) when the company rolls out full year 2020 guidance early next year.
An additional credit negative that I did not specifically factor into the above analysis is the 2017 tax reform bill. While the bill has benefited corporates broadly speaking, as Julie Lieberman with Concentric Energy Advisors noted last October, it contains significant cash flow and credit negatives for utilities:
Utility credit profiles have suffered from the lower operating cash flows associated with the corporate tax rate reduction from 35% to 21%, but also from the past over-collection of future income taxes which now must be returned to customers. Other features of the law eliminate bonus depreciation for utilities, which has historically allowed utilities to defer substantial accumulated tax balances. Alternately, it has also allowed utilities to retain full deductibility of corporate interest expense which under the law is limited for the broader corporate sector. Regulated utilities’ revenue requirements are now exposed to substantial potential reductions, which will reduce cash flows and strain credit metrics, and in many cases, credit ratings.
Consistently poor ROICs should pressure valuation multiples, and the resulting unwind could lead to a cascade of selling as low volatility ETFs divest large utility industry weightings
One of the mysteries (at least to this author) of the regulated utility business is that despite being regulated to earn 10% ROEs, the actual economics of the business fall far short. On three different measures, WEC has only just covered its cost of capital for the last four years. To WEC management’s credit, its peers have done worse: investor-owned electric utilities collectively have not generated positive free cash flow since 2011. One investor recently pointed out that since 2008, the U.S. electric utility industry has generated $8 billion of incremental EBIT on incremental capital of $700 billion. Why should this company and industry trade at premium multiples of EPS, EBITDA, and book value?
Source: WEC SEC filings
Source: Edison Electric Institute
If and when the market does come around to broader utility overvaluation, the industry will likely sell off as one, with little regard to individual company economics or growth prospects. The three largest large cap low volatility ETFs collectively hold approximately $7 billion in market cap of regulated utilities. While not large relative to aggregate utility industry market cap, it’s important to understand how the rebalancing mechanisms could accelerate a selloff once underway. All three of the ETFs employ one or more varieties of trailing realized volatility calculations to put together their portfolios. They are essentially momentum vehicles by another name: low trailing realized volatility tends to correlate highly with steady upward price movement, and vice versa. Once names begin to selloff, realized volatility increases, and the ETF must sell.
To back up the assertion that utilities generally trade with little intra-industry differentiation, we can employ principal components analysis. Principal components analysis is a statistical procedure that converts sets of observations (in our case, daily log returns for ETF holdings over the last five years) into a set of values of linearly uncorrelated variables called principal components. The first principal component is chosen to represent the largest possible variance in the data, and each subsequent component in turn has the highest possible variance such that it is orthogonal to the preceding components. While not strictly mathematically accurate, for our purposes we can think of principal components as uncorrelated latent factors that explain stock price movements.
By running PCA on 17 of the 20 largest holdings (the other three have short trading histories) in the low volatility ETF SPLV, we find that 73% of the total variation in daily log returns is explained by the first three principal components (out of 17 potential principal components). Remember that the last five years captures rising and falling interest rate environments, multiple sector rotations, and significant up and down equity market cycles.
See the clump floating in the far right corner of the plot? Those dots represent NEE, DUK, ETR, ES, AEP, D, WEC, CMS, SRE, PEG, and CNP: all regulated utilities. Across a range of market cycles, these names have traded in virtual lockstep even as the individual constituents have exhibited a considerable amount of variance with respect to EPS and dividend growth guidance and returns on capital.